The accompanying notes are an integral part of these condensed consolidated financial statements.
9
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(in thousands)
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 | | | January 1, 2018 | | Nine |
| | Through | | | Through | | Months Ended |
| | September 30, 2018 | | | February 8, 2018 | | September 30, 2017 |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net loss | $ | (39,204 | ) | | | $ | (14,892 | ) | | $ | (14,603 | ) |
| Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | |
| Depreciation, depletion and amortization expense | 83,068 |
| | | 12,414 |
| | 80,082 |
|
| Impairment expense | — |
| | | 5,560 |
| | 29,206 |
|
| Accretion expense | 489 |
| | | 140 |
| | 1,447 |
|
| Amortization of deferred financing costs | 151 |
| | | 171 |
| | 2,205 |
|
| Amortization of debt premium | (3,281 | ) | | | — |
| | — |
|
| Equity-based compensation expense | 6,714 |
| | | — |
| | — |
|
| Dry hole expense | — |
| | | (45 | ) | | 2,447 |
|
| Expired leases | 10,658 |
| | | 1,250 |
| | 8,394 |
|
| (Gain) loss on derivative contracts | 63,077 |
| | | (7,298 | ) | | (38,024 | ) |
| Cash settlements of derivative contracts | (32,836 | ) | | | (1,661 | ) | | 1,775 |
|
| Premium paid on derivative contracts | — |
| | | — |
| | (520 | ) |
| Interest converted into debt | — |
| | | 103 |
| | 904 |
|
| Interest added to notes receivable due from related party | (680 | ) | | | (85 | ) | | (619 | ) |
| Loss on sale of assets and other | 81 |
| | | 1,923 |
| | — |
|
| Gain on acquisition of oil and gas properties | — |
| | | — |
| | (6,893 | ) |
| Impact on cash from changes in assets and liabilities: | | | | | | |
| Accounts receivable | (5,715 | ) | | | (20,895 | ) | | (33,649 | ) |
| Other receivables | 976 |
| | | (9,887 | ) | | 7,382 |
|
| Receivables due from affiliate | (16,656 | ) | | | — |
| | — |
|
| Receivables due from related party | (12,178 | ) | | | (117 | ) | | 169 |
|
| Prepaid expenses and other current and non-current assets | 8,181 |
| | | 9,970 |
| | (9,938 | ) |
| Advances from related party | (30,589 | ) | | | 24,116 |
| | 5,266 |
|
| Settlement of asset retirement obligations | (1,249 | ) | | | (63 | ) | | (6,083 | ) |
| Accounts payable — related party | (4,994 | ) | | | — |
| | — |
|
| Accounts payable, accrued liabilities and other liabilities | (10,531 | ) | | | 25,815 |
| | 27,308 |
|
| NET CASH PROVIDED BY OPERATING ACTIVITIES | 15,482 |
|
| | 26,519 |
|
| 56,256 |
|
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | |
| Capital expenditures for property and equipment | (489,009 | ) | | | (38,096 | ) | | (244,308 | ) |
| Acquisitions | — |
| | | — |
| | (55,236 | ) |
| Proceeds from sale of assets and other, net | 11 |
| | | — |
| | — |
|
| Notes receivable due from affiliate | — |
| | | — |
| | (1,515 | ) |
| NET CASH USED IN INVESTING ACTIVITIES | (488,998 | ) | | | (38,096 | ) | | (301,059 | ) |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | |
| Proceeds from issuances of long-term debt | 80,000 |
| | | 60,000 |
| | 286,065 |
|
| Repayments of long-term debt | (134,065 | ) | | | (43,000 | ) | | (251,622 | ) |
| Additions to deferred financing costs | (1,367 | ) | | | — |
| | (220 | ) |
| Capital distributions | (32,000 | ) | | | (68 | ) | | — |
|
| Capital contributions | 560,344 |
| | | — |
| | 207,875 |
|
| NET CASH PROVIDED BY FINANCING ACTIVITIES | 472,912 |
|
| | 16,932 |
|
| 242,098 |
|
| NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH | (604 | ) | | | 5,355 |
| | (2,705 | ) |
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period | 10,345 |
| | | 4,990 |
| | 7,618 |
|
| CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period | $ | 9,741 |
|
| | $ | 10,345 |
|
| $ | 4,913 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash flows from operating activities: | | | | | | |
| Net loss | $ | (16,979 | ) | | $ | (57,078 | ) | | | $ | (14,862 | ) |
| Adjustments to reconcile net loss to cash from operating activities: | | | | | | |
| Depreciation, depletion, amortization and accretion | 69,179 |
| | 37,708 |
| | | 12,554 |
|
| Non-cash lease expense | 1,587 |
| | — |
| | | — |
|
| Provision for uncollectible receivables | 1,177 |
| | — |
| | | — |
|
| Impairment of assets | 6,500 |
| | — |
| | | 5,560 |
|
| Amortization of deferred financing costs | 139 |
| | 80 |
| | | 171 |
|
| Amortization of debt (premium) discount | (2,462 | ) | | (2,051 | ) | | | — |
|
| Equity-based compensation expense | 3,057 |
| | 6,389 |
| | | — |
|
| Non-cash exploration expense | 388 |
| | 10,658 |
| | | 4,575 |
|
| (Gain) loss on derivatives | 11,365 |
| | 51,230 |
| | | (6,663 | ) |
| Cash settlements of derivatives | 909 |
| | (18,334 | ) | | | (2,296 | ) |
| Premium paid on derivatives | (1,000 | ) | | — |
| | | — |
|
| Interest converted into debt | — |
| | — |
| | | 103 |
|
| Interest added to notes receivable from affiliate | — |
| | (417 | ) | | | (85 | ) |
| Loss on sale of fixed assets | — |
| | 63 |
| | | 1,923 |
|
| Impact on cash from changes in: | | | | | | |
| Accounts receivable | 6,384 |
| | (2,923 | ) | | | (21,184 | ) |
| Other receivables | 2,737 |
| | 1,426 |
| | | (662 | ) |
| Receivables from related parties | 10,280 |
| | (18,494 | ) | | | (117 | ) |
| Prepaid expenses and other non-current assets | (3,853 | ) | | 7,810 |
| | | (591 | ) |
| Advances from related party | (5,819 | ) | | (10,371 | ) | | | 24,116 |
|
Settlement of asset retirement obligations
| — |
| | (806 | ) | | | (63 | ) |
Accounts payable to related party
| (3,203 | ) | | (4,994 | ) | | | — |
|
| Accounts payable, accrued liabilities and other liabilities | (17,281 | ) | | (45,385 | ) | | | 23,857 |
|
| Operating lease obligations | (1,287 | ) | | — |
| | | — |
|
| Cash from operating activities | 61,818 |
| | (45,489 | ) | | | 26,336 |
|
| Cash flows from investing activities: | | | | | | |
| Capital expenditures | (180,138 | ) | | (319,042 | ) | | | (36,695 | ) |
| Acquisitions, net of cash acquired | — |
| | — |
| | | (1,218 | ) |
| Proceeds from sale of assets | — |
| | 11,299 |
| | | — |
|
| Cash from investing activities | (180,138 | ) | | (307,743 | ) | | | (37,913 | ) |
| Cash flows from financing activities: | | | | | | |
| Proceeds from long-term debt borrowings | 183,500 |
| | — |
| | | 60,000 |
|
| Repayments of long-term debt | — |
| | (134,065 | ) | | | (43,000 | ) |
| Deferred financing costs paid | — |
| | (1,366 | ) | | | — |
|
| Capital distributions | — |
| | (7,000 | ) | | | (68 | ) |
| Capital contributions | — |
| | 560,344 |
| | | — |
|
| Cash from financing activities | 183,500 |
| | 417,913 |
| | | 16,932 |
|
| Net increase in cash, cash equivalents and restricted cash | 65,180 |
| | 64,681 |
| | | 5,355 |
|
| Cash, cash equivalents and restricted cash, beginning of period | 13,985 |
| | 10,345 |
| | | 4,990 |
|
| Cash, cash equivalents and restricted cash, end of period | $ | 79,165 |
| | $ | 75,026 |
| | | $ | 10,345 |
|
The accompanying notes are an integral part of these condensed consolidated financial statements.
10
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Alta Mesa Holdings, LP together with its subsidiaries (“we,” “us,” “our,” the “Company,” and “AltaAlta Mesa” or “the Company”), is an exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basinOklahoma commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”).
As described further in Note 5 — Business Combination, certain transactions were consummated onSTACK. Our operations prior to February 9, 2018, that resultedalso included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”). These transactions are referred to as the “Business Combination”. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of , on February 9, 2018 (“the Business Combination, we were controlled by High Mesa Inc. (“High Mesa”Combination”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.
In connection with the closing of the Business Combination,, we distributed ourthe non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (the “AM Contributor”(“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK.
NOTE 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, 2017 (the “2017 Annual Report”). As of September 30, 2018, our significant accounting policies are consistent with those discussed in Note 2 in the 2017 Annual Report, other than as noted below.
Basis of Presentation. As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree. PursuantPrior to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations, (“ASC 805”), our identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”). Fair value adjustments related to the transaction have been pushed down to us resulting in our assets and liabilities being recorded at fair value as of the acquisition date. As a result of the Transactions described above, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. The Successor periods presented herein are for the three months ended September 30, 2018 and from February 9, 2018 to September 30, 2018 (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three months ended September 30, 2017 and the nine months ended September 30, 2017 (“2017 Predecessor Period,” and, together with the 2018 Predecessor Period, the “Predecessor Periods”).
As noted above, we distributed our non-STACK assets and liabilities to the AM Contributor in connection with the closing of the Business Combination.Combination, we were controlled by High Mesa Inc. (“HMI”). The distribution of2018 10-K contains substantially more information about our non-STACK assets and liabilitiesoperations and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin. As a result, weBusiness Combination.
All intercompany transactions and accounts have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within thebeen eliminated. These interim condensed consolidated financial statements. See Note 7 — Discontinued Operations (Predecessor)statements are unaudited, but we believe these statements reflect all adjustments necessary for further discussion.
Principlesa fair presentation for the periods reported. All such adjustments are of Consolidationa normal, recurring nature unless otherwise disclosed. These financial statements and Reporting. The accompanying condensed consolidated financial statementsdisclosures have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”)SEC’s rules for interim financial informationstatements and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotesdisclosures required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances.
The condensed consolidated financial statements included herein as of September 30, 2018, and for the three months ended September 30, 2018 (Successor) and the period from February 9, 2018 through September 30, 2018 (Successor), the period from January 1, 2018 through February 8, 2018 (Predecessor) and the three and nine months ended September 30, 2017 (Predecessor),
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 condensed consolidatedgenerally accepted accounting principles (“GAAP”). These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our annual consolidated financial statements2018 10-K. The results for the yearthree and six months ended December 31, 2017, which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periodsJune 30, 2019, are not necessarily indicative of the results to be expected for athe full year.
The Company’s condensed consolidated statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain otherWe have no items of other comprehensive income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.
Use of Estimates. The preparation of condensed 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 condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.any period presented.
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. Other estimates are utilized to determine amounts related to oil and natural gas revenues, the value of oil and natural gas properties, the value of other property and equipment, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Restricted Cash. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows (in thousands):
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | September 30,
2018 | | | December 31,
2017 |
| Cash and cash equivalents | $ | 8,869 |
| | | $ | 3,660 |
|
| Restricted cash | 872 |
| | | 1,269 |
|
| Cash of discontinued operations | — |
| | | 61 |
|
| Total cash, cash equivalents and restricted cash | $ | 9,741 |
|
| | $ | 4,990 |
|
Bond Premium on Senior Unsecured Notes. As a result of the pushdown accounting related to the Business Combination, the Company estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million as of the acquisition date. The amount in excess of the original principal balance was recorded as a bond premium, which is being amortized as a reduction to interest expense.
Equity-Based Compensation (Successor). The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options, restricted stock and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock awards and performance-based restricted stock units are valued using the market price of AMR’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 16 — Equity-Based Compensation for additional information regarding the Company’s equity based compensation.
Going Concern. The Company’s management is
We are required to evaluate an entity’sour ability to continue as a going concern for a period of one year following the date of the issuance of the Company’s consolidatedour financial statements. DisclosureAs part of that evaluation, we took into consideration the following factors:
Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination.
Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties.
Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions.
On April 1, 2019, our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019. Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million, we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is requireddue in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is
a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities.
We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019.
We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value.
The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets.
Our ability to collect receivables due from High Mesa and its affiliates
The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have:
retained financial advisors to assist in evaluating financial alternatives;
engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief;
considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and
engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal.
Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists about an entity’sregarding our ability to continue as a going concern duringfor the evaluation period, including management’s plans to alleviate the conditions and events that raise substantial doubt of going concern, if applicable.
At the date of12 months following the issuance of these consolidated financial statements, management considersstatements. Based on the Companyforegoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current.
Recently Issued Accounting Standards Applicable to beUs
Adopted
Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a going concernlease liability, which is a lessee’s discounted obligation to make payments under a lease and has prepared these consolidated financial statements on a going concern basis.right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019.
Not Yet Adopted
Recent Accounting Pronouncements Issued But Not Yet AdoptedIn June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses(Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract(“ (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a
hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. The CompanyWe will adopt this new standard at the same time as our parent company, which will be no later than the fiscal year beginning after December 15, 2019,January 1, 2020, although early adoption is permitted. The Company isWe are currently evaluating the impact of this new standard on itsour consolidated financial position and results of operations and hashave not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation.
ASU 2014-09, as amended, is effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act.
ASU 2014-09 allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company, we previously elected to use the extended transition period to defer implementation of the new standard until the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR, our parent company, is also an emerging growth company, but will cease to be an emerging growth company on December 31, 2018, which will require them to adopt ASU 2014-09 on December 31, 2018, with modified retroactive implementation as of January 1, 2018. Accordingly, we will also adopt ASU 2014-09 at the same time as our parent company.
We are continuing our review of contracts for each of our revenue streams and evaluating the impact on our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09, as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant accounting policies and internal controls, if needed. Based on assessments performed to date, we do not expect ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we currently expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to natural gas processing contracts; however, the impact of such presentation changes will not impact our consolidated operating income, net income or cash flows.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), 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 (except for short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a 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. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In JanuaryAugust 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for transition to Topic 842Fair Value Measurement (“ASU 2018-01”2018-13”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. The standard, as amended, will bemodifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for interim and annual periodsus beginning after December 15, 2018. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets.
The standard provides several optional practical expedients in transition. We expect to elect the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date. We also expect to elect the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we expect to elect the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019.2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect to elect the use-of-hindsight practical expedient.
At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption may also result in a change in the amount of lease expense recorded on our consolidated statements of operations, as well as add additional disclosures. We expect our implementation work team will complete its evaluation of this new standard by the end of 2018.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), 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 and interim periods within those fiscal years beginning after December 15, 2017. As an emerging growth company, we had elected to use the extended transition period to defer adoption of this standard until 2019. However, our parent company will lose its emerging growth status, effective December 31, 2018. Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. The adoption of this guidance will not impact our financial position or results of operations but could result in presentational changes in our consolidated statements of cash flows.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model used today. With respect to our trade receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations.
NOTE 3 — ADOPTION OF ASU NO. 2016-02, LEASES
ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities of $15.0 million. There was no adjustment to beginning of period equity.
We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets, although we aspire to sublease our unused office lease space.
Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred.
Upon adoption, we selected the following practical expedients:
|
| | |
| Practical expedient package | | We did not reassess whether any expired or existing contracts are, or contain, leases. |
| | We did not reassess the lease classification of any expired or existing leases. |
| | We did not reassess initial direct costs of any expired or existing leases. |
| | |
| Hindsight practical expedient | | We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. |
| | |
| Easement expedient | | We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. |
| | |
| Combining lease and non-lease components expedient | | We elected to account for lease and non-lease components as a single component. |
| | |
| Short-term lease expedient | | We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet. |
As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019, for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and our weighted-average discount rates were 14.1%.
Lease Costs
|
| | | | | | | | |
| (in thousands) | | Three Months Ended
June 30, 2019 | | Six Months Ended June 30, 2019 |
| Operating lease cost | | $ | 776 |
| | $ | 1,587 |
|
| Variable lease cost | | 473 |
| | 796 |
|
| Short-term lease cost | | 1,075 |
| | 3,261 |
|
| Total lease cost | | $ | 2,324 |
| | $ | 5,644 |
|
| | | | | |
| Reported as: | | | | |
| Lease operating expense | | $ | 1,031 |
| | $ | 3,326 |
|
| General and administrative expense | | 1,293 |
| | 2,318 |
|
| Total lease cost | | $ | 2,324 |
| | $ | 5,644 |
|
Operating Lease Liability Maturities as of June 30, 2019
|
| | | | |
| Fiscal year | | (in thousands) |
| Remainder of 2019 | | $ | 1,470 |
|
| 2020 | | 2,965 |
|
| 2021 | | 2,942 |
|
| 2022 | | 3,010 |
|
| 2023 | | 2,718 |
|
| Thereafter | | 12,647 |
|
| Total lease payments | | 25,752 |
|
| Less: imputed interest | | (11,081 | ) |
| Present value of operating lease liabilities | | $ | 14,671 |
|
| | | |
| Current portion of operating lease liabilities | | $ | 938 |
|
| Operating lease liabilities, net of current portion | | 13,733 |
|
| Present value of operating lease liabilities | | $ | 14,671 |
|
Operating Lease Payment Obligations as of December 31, 2018
As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter.
Right-of-Use Asset Impairment
During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.
NOTE 3 4 — SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands):
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 | | | January 1, 2018 | | Nine |
| | Through | | | Through | | Months Ended |
| | September 30, 2018 | | | February 8, 2018 | | September 30, 2017 |
| Supplemental cash flow information: | | | | | | |
| Cash paid for interest | $ | 22,073 |
| | | $ | 1,145 |
| | $ | 25,675 |
|
| Cash paid for state income taxes | 7 |
| | | — |
| | — |
|
| Non-cash investing and financing activities: | | | | | | |
| Increase in asset retirement obligations | 4,652 |
| | | — |
| | 3,778 |
|
| Asset retirement obligations assumed, purchased properties | — |
| | | — |
| | 705 |
|
| Increase in accruals or payables for capital expenditures | 35,967 |
| | | 4,712 |
| | 41,322 |
|
| Distribution of non-STACK (assets) net liability | — |
| | | 33,102 |
| | — |
|
| Increase in accounts receivable for sale of assets | (524 | ) | | | — |
| | — |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Supplemental cash flow information: | | | | | | |
| Cash paid for interest | $ | 25,070 |
| | $ | 21,216 |
| | | $ | 1,145 |
|
| Cash paid for state income taxes, net of refunds | — |
| | 6 |
| | | — |
|
| Non-cash investing and financing activities: | | | | | | |
| Increase in asset retirement obligations | 634 |
| | 877 |
| | | — |
|
| Increase (decrease) in accruals or payables for capital expenditures | (91,639 | ) | | (27,646 | ) | | | 4,896 |
|
| Distribution of non-STACK assets, net of liabilities | — |
| | — |
| | | 43,482 |
|
We aggregate cash, cash equivalents and restricted cash in the statements of cash flows.
NOTE 4 5 — ACCOUNTS RECEIVABLE RECEIVABLES
Accounts receivable consisted of the following (in thousands):
Receivable
| | | | Successor | | | Predecessor | |
| | September 30,
2018 | | | December 31,
2017 | |
| Oil, natural gas and natural gas liquids sales | $ | 40,134 |
| | | $ | 26,916 |
| |
| (in thousands) | | June 30, 2019 | | December 31, 2018 |
| Production sales | | $ | 29,730 |
| | $ | 31,532 |
|
| Joint interest billings | 44,548 |
| | | 13,821 |
| 20,836 |
| | 18,147 |
|
Pooling interest (1) | 23,367 |
| | | 35,839 |
| 11,506 |
| | 18,786 |
|
| Allowance for doubtful accounts | (65 | ) | | | (415 | ) | (410 | ) | | (95 | ) |
| Total accounts receivable, net | $ | 107,984 |
|
| | $ | 76,161 |
| $ | 61,662 |
| | $ | 68,370 |
|
_________________
| |
| (1) | Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offerpermits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs of unbilled interests onfor wells whichwhere the Company incurred before the pooling process was completed.option remains pending. Depending upon the outcome of the pooling process,mineral owner’s decision, these costs maywill be billed to potential working interest ownersthem or added to oil and gas properties. |
NOTE 5 — BUSINESS COMBINATIONRelated Party Receivables
|
| | | | | | | |
| (in thousands) | June 30, 2019 | | December 31, 2018 |
| Related party receivables | $ | 23,037 |
| | $ | 33,316 |
|
| Allowance for doubtful accounts | (9,888 | ) | | (9,034 | ) |
| Related party receivables, net | 13,149 |
| | 24,282 |
|
| | | | |
| Notes receivable from related parties | 13,403 |
| | 13,403 |
|
| Allowance for doubtful accounts | (13,403 | ) | | (13,403 | ) |
| Notes receivable from related parties, net | — |
| | — |
|
| Total related party receivables, net | $ | 13,149 |
| | $ | 24,282 |
|
On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreement, dated August 16, 2017, with AMR (formerly Silver Run Acquisition Corporation II), AM Contributor, High Mesa Holdings GP, LLC, the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor (“AM Contribution Agreement”). Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement, dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor (the “KFM Contribution Agreement”); and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”).Receivables
Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”), acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The
acquisition of us and Kingfisher pursuantWe have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the Contribution Agreements is referred to herein assix months ended June 30, 2019, the “Business Combination”period February 9, 2018 through June 30, 2018, and the transactions contemplatedPredecessor Period, we incurred $30.8 million, $13.6 million, and $3.1 million, respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the Contribution Agreements are referredfees from midstream services that KFM provided to herein as the “Transactions.” As a result of the Transactions, AMR has obtained control over the management of AMH GPus totaling $4.6 million and consequently, us.$11.2 million at June 30, 2019 and December 31, 2018, respectively.
At the closing of the Transactions, the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco. The AM Contributor also acquired from AMRIn addition, we sold a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), correspondingproduced water disposal system to the number of Common Units received by the AM Contributor at closing.
Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20-day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”):
|
| | |
20-Day
VWAP
| | Earn-Out Consideration |
$14.00 | | 10,714,285 Common Units |
$16.00 | | 9,375,000 Common Units |
$18.00 | | 13,888,889 Common Units |
$20.00 | | 12,500,000 Common Units |
The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles.
AMR also contributed $560 million in net cash to us at the closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements. We used a portion of the amount to repay all outstanding balance under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net.
Pursuant to the AM Contribution Agreement, AM Contributor delivered a final closing statementKFM during the secondfourth quarter of 2018. Based on the final closing statement, the AM Contributor received an additional 1,197,934 SRII Opco Common Units and an equivalent numberAs of sharesDecember 31, 2018, related party receivables of AMR’s Class C Common Stock.$8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019.
The Business Combination has been accountedAMR Receivables
We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of June 30, 2019 and December 31, 2018, respectively, we have receivables from AMR for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination (“ASC 805”),such costs totaling $8.5 million and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that our assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by AMR, who was determined to be the accounting acquirer. We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed. Pursuant to ASC 805, finalization of the values is to be completed within one year of the acquisition date.$3.3 million, respectively.
Management Services Agreement with High Mesa
Preliminary Estimated Purchase Price
AMR’s preliminary estimated purchase price consideration for Alta Mesa was as follows (in thousands):
|
| | | | | | | | | | | |
| | February 9, 2018 (As initially reported) | | Measurement Period Adjustment (1) | | February 9, 2018 (As adjusted) |
Preliminary Purchase Consideration: (2) | | | | | |
SRII Opco Common Units issued (3) | $ | 1,251,782 |
| | $ | 9,467 |
| | $ | 1,261,249 |
|
Estimated fair value of contingent earn-out purchase consideration (4) | 284,109 |
| | — |
| | 284,109 |
|
| Total purchase price consideration | $ | 1,535,891 |
| | $ | 9,467 |
| | $ | 1,545,358 |
|
|
| | | |
| (in thousands) | June 30, 2019 |
| High Mesa related party receivable at December 31, 2018 | $ | 10,066 |
|
| Additions | 894 |
|
| Payments | (1,072 | ) |
| High Mesa related party receivable at June 30, 2019 | 9,888 |
|
Allowance for uncollectibility(1) | (9,888 | ) |
| Balance at June 30, 2019, net | $ | — |
|
_________________
| |
| (1) | The measurement period adjustment relates to$9.0 million of the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the partiesallowance was recognized during the three months ended June 30, 2018 (Successor). |
| |
(2) | The preliminary purchase price consideration is for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP. |
| |
(3) | At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. |
| |
(4) | For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million, which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.
Successor Period. |
Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180-day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180-day periods, unless terminated by either party upon at least 90-days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services.
Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019, and December 31, 2018, approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018, respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation
Preliminary Estimated Purchase Price Allocationrelating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa.
Promissory notes receivable
In September, 2017, we entered into a $1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The allocationpromissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note when it was not paid at maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018.
In addition, we have an $8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. HMI disputes its obligations under the $8.5 million note. As of June 30, 2019, and December 31, 2018, the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods.
We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s preliminary estimatedirectors who are also controlling holders of the purchase considerationHMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to the assets acquired and liabilities assumed in the acquisition of Alta Mesa was as follows (in thousands):this matter.
NOTE 6 — PROPERTY AND EQUIPMENT
|
| | | | | | | | | | | |
| | February 9, 2018 (As initially reported) | | Measurement Period Adjustment (1) | | February 9, 2018 (As adjusted) |
Estimated Fair Value of Assets Acquired (2) | | | | | |
| Cash, cash equivalents and short term restricted cash | $ | 10,345 |
| | $ | — |
| | $ | 10,345 |
|
| Accounts receivable | 101,745 |
| | — |
| | 101,745 |
|
| Other receivables | 1,222 |
| | — |
| | 1,222 |
|
| Receivables due from related party | 907 |
| | — |
| | 907 |
|
| Prepaid expenses and other current assets | 1,405 |
| | — |
| | 1,405 |
|
| Derivative financial instruments | 352 |
| | — |
| | 352 |
|
Property and equipment: (3) | | | | | |
| Oil and natural gas properties, successful efforts | 2,314,858 |
| | (1,479 | ) | | 2,313,379 |
|
| Other property and equipment, net | 43,318 |
| | — |
| | 43,318 |
|
| Notes receivable due from related party | 12,454 |
| | — |
| | 12,454 |
|
| Deposits and other long-term assets | 10,286 |
| | — |
| | 10,286 |
|
| Total fair value of assets acquired | 2,496,892 |
| | (1,479 | ) | | 2,495,413 |
|
Estimated Fair Value of Liabilities Assumed (2) | | | | | |
| Accounts payable and accrued liabilities | 210,867 |
| | (10,946 | ) | | 199,921 |
|
| Accounts payable — affiliate | 5,476 |
| | — |
| | 5,476 |
|
| Advances from non-operators | 6,803 |
| | — |
| | 6,803 |
|
| Advances from related party | 47,506 |
| | — |
| | 47,506 |
|
Asset retirement obligations (3) | 5,998 |
| | — |
| | 5,998 |
|
| Derivative financial instruments | 11,585 |
| | — |
| | 11,585 |
|
Long-term debt (4) | 667,700 |
| | — |
| | 667,700 |
|
| Other long-term liabilities | 5,066 |
| | — |
| | 5,066 |
|
| Total fair value of liabilities assumed | 961,001 |
| | (10,946 | ) | | 950,055 |
|
| Total consideration and fair value | $ | 1,535,891 |
| | $ | 9,467 |
| | $ | 1,545,358 |
|
|
| | | | | | | |
| (in thousands) | June 30, 2019 | | December 31, 2018 |
| Oil and gas properties | | | |
| Unproved properties | $ | 76,665 |
| | $ | 74,217 |
|
| Proved oil and gas properties | 2,196,605 |
| | 2,110,346 |
|
| Accumulated depletion and impairment | (1,489,191 | ) | | (1,421,226 | ) |
| Proved oil and gas properties, net | 707,414 |
| | 689,120 |
|
| Total oil and gas properties, net | 784,079 |
| | 763,337 |
|
| Other property and equipment | | | |
| Land | 5,059 |
| | 5,059 |
|
| Fresh water wells | 27,372 |
| | 27,366 |
|
| Produced water disposal system | 3,590 |
| | 3,608 |
|
| Office furniture, equipment and vehicles | 2,825 |
| | 2,840 |
|
| Accumulated depreciation | (1,475 | ) | | (726 | ) |
| Other property and equipment, net | 37,371 |
| | 38,147 |
|
| Total property and equipment, net | $ | 821,450 |
| | $ | 801,484 |
|
_________________
| |
(1) | The measurement period adjustments are recognized in the reporting period in which the adjustments were determined and calculated as if the accounting had been completed at the acquisition date. |
| |
(2) | The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets. |
| |
(3) | The estimated fair values of oil and natural gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates. |
| |
(4) | Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024, totaling approximately $533.6 million, based on Level 1 inputs, and outstanding borrowings under the Eighth A&R credit facility (described in Note 11 — Long-Term Debt, Net) of approximately $134.1 million as of the acquisition date.
|
NOTE 6 — PROPERTY AND EQUIPMENTDepletion and Depreciation Expense
Property and equipment consisted of the following (in thousands):
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | September 30,
2018 | | | December 31,
2017 |
| OIL AND NATURAL GAS PROPERTIES | | | | |
| Unproved properties | $ | 865,695 |
| | | $ | 84,590 |
|
| Accumulated impairment of unproved properties | — |
| | | — |
|
| Unproved properties, net | 865,695 |
|
| | 84,590 |
|
| Proved oil and natural gas properties | 1,913,526 |
| | | 1,061,105 |
|
| Accumulated depreciation, depletion, amortization and impairment | (81,464 | ) | | | (251,065 | ) |
| Proved oil and natural gas properties, net | 1,832,062 |
|
| | 810,040 |
|
| TOTAL OIL AND NATURAL GAS PROPERTIES, net | 2,697,757 |
|
| | 894,630 |
|
| OTHER PROPERTY AND EQUIPMENT | | | | |
| Land | 5,059 |
| | | 2,912 |
|
| Salt water disposal system | 88,176 |
| | | 30,990 |
|
| Office furniture and equipment and vehicles | 2,325 |
| | | 20,008 |
|
| Accumulated depreciation | (1,604 | ) | | | (21,770 | ) |
| OTHER PROPERTY AND EQUIPMENT, net | 93,956 |
|
| | 32,140 |
|
| TOTAL PROPERTY AND EQUIPMENT, net | $ | 2,791,713 |
|
| | $ | 926,770 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Three Months Ended
June 30, 2019 | | Three Months Ended
June 30, 2018 | | | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Oil and gas properties depletion | $ | 33,923 |
| | $ | 26,086 |
| | | $ | 67,965 |
| | $ | 36,859 |
| | | $ | 11,021 |
|
| Other property and equipment depreciation | 341 |
| | 423 |
| | | 749 |
| | 586 |
| | | 609 |
|
| Total depletion and depreciation | $ | 34,264 |
| | $ | 26,509 |
| | | $ | 68,714 |
| | $ | 37,445 |
| | | $ | 11,630 |
|
In conjunction with pushdown accounting,Impairment
During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment was measured at fair value asequipment. Therefore, we did not conduct further analysis on the recognition of the acquisition date, which also impacted how value was assigned between the categories within property and equipment (see Note 5 — Business Combination for details).additional impairment.
NOTE 7 — DISCONTINUED OPERATIONS (Predecessor)
WeAlta Mesa distributed ourthe non-STACK oil and gas assets and related liabilities to the AM ContributorHigh Mesa immediately prior to the Closing Date of the Business Combination. TheThis distribution, including the results of our non-STACK assets and related liabilities and the saleoperations of our Weeks Island field during the fourth quarter of 2017 were part of our overall strategic shift to operate only in the eastern Anadarko Basin. As a result, the Predecessor’s non-STACKthese assets and liabilities, have beenis presented as discontinued operations induring the consolidated balance sheets. The operating results directly related to non-STACK assets and liabilities have been segregated and presented as discontinued operations within the condensed consolidated financial statements in the 2018 Predecessor Period and the 2017 Predecessor Periods. Period.
Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10%. In connection with the Transactions described in Note 5 –Business Combination, the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million, including accrued interest. Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million and $0.9 million for the three months ended September 30, 2017 (Predecessor) and 2017 Predecessor Period, respectively. |
| | | |
| | Predecessor |
| (in thousands) | January 1, 2018
Through
February 8, 2018 |
| Revenue | |
| Oil | $ | 1,617 |
|
| Natural gas | 1,023 |
|
| Natural gas liquids | 236 |
|
| Other | 16 |
|
| Operating revenue | 2,892 |
|
| Loss on sale of assets | (1,923 | ) |
| Total revenue | 969 |
|
| Operating expenses | |
| Lease operating | 1,770 |
|
| Transportation and marketing | 83 |
|
| Production taxes | 167 |
|
| Workovers | 127 |
|
| Depreciation, depletion and amortization | 884 |
|
| Impairment of assets | 5,560 |
|
| General and administrative | 21 |
|
| Total operating expenses | 8,612 |
|
| Other expense | |
| Interest expense | (103 | ) |
| Loss from discontinued operations, net of tax | $ | (7,746 | ) |
The assets and liabilities directly related to the non-STACK assets presented as discontinued operations in the condensed consolidated balance sheets were as follows (in thousands):
|
| | | |
| | Predecessor |
| | December 31, 2017 |
| Assets associated with discontinued operations: | |
| Current assets | |
| Cash | $ | 61 |
|
| Accounts receivable | 4,980 |
|
| Other receivables | 154 |
|
| Total current assets | 5,195 |
|
| Noncurrent assets | |
| Investments in LLC - Cost | 9,000 |
|
| Proved oil and natural gas properties, net | 15,408 |
|
| Unproved properties, net | 15,504 |
|
| Land | 2,706 |
|
| Other long-term assets | 1,167 |
|
| Total noncurrent assets | 43,785 |
|
| Total assets associated with discontinued operations | $ | 48,980 |
|
| | |
| Liabilities associated with discontinued operations: | |
| Current liabilities | |
| Accounts payable and accrued liabilities | $ | 7,882 |
|
| Asset retirement obligations | 7,537 |
|
| Total current liabilities | 15,419 |
|
| Noncurrent liabilities | |
| Asset retirement obligations, net of current | 37,049 |
|
| Founder notes | 28,166 |
|
| Other long-term liabilities | 1,647 |
|
| Total noncurrent liabilities | 66,862 |
|
| Total liabilities associated with discontinued operations | $ | 82,281 |
|
The operating results directly related to the non-STACK assets and liabilities presented as discontinued operations within the condensed consolidated financial statements were as follows (in thousands):
|
| | | | | | | | | | | |
| | Predecessor |
| | Three Months Ended
September 30, 2017 | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Operating revenues and other: | | | | | |
| Oil | $ | 10,994 |
| | $ | 1,617 |
| | $ | 36,122 |
|
| Natural gas | 2,376 |
| | 1,023 |
| | 7,964 |
|
| Natural gas liquids | 571 |
| | 236 |
| | 1,613 |
|
| Other revenues | 72 |
| | 16 |
| | 274 |
|
| Total operating revenues | 14,013 |
| | 2,892 |
|
| 45,973 |
|
| Loss on sale of assets | — |
| | (1,923 | ) | | — |
|
| Gain on acquisition of oil and gas properties | — |
| | — |
| | 1,626 |
|
| Total operating revenues and other | 14,013 |
| | 969 |
|
| 47,599 |
|
| Operating expenses: | | | | | |
| Lease operating expense | 6,888 |
| | 1,770 |
| | 21,944 |
|
| Marketing and transportation expense | 352 |
| | 83 |
| | 1,080 |
|
| Production taxes | 1,443 |
| | 167 |
| | 5,100 |
|
| Workover expense | 273 |
| | 127 |
| | 1,981 |
|
| Exploration expense | 1,874 |
| | — |
| | 8,042 |
|
| Depreciation, depletion and amortization | 4,625 |
| | 630 |
| | 16,835 |
|
| Impairment expense | 82 |
| | 5,560 |
| | 28,018 |
|
| Accretion expense | 287 |
| | 101 |
| | 1,213 |
|
| General and administrative expense | 13 |
| | 21 |
| | 60 |
|
| Total operating expenses | 15,837 |
| | 8,459 |
|
| 84,273 |
|
| Other income (expense) | | | | | |
| Interest expense | (305 | ) | | (103 | ) | | (904 | ) |
| Interest income and other | 88 |
| | — |
| | 88 |
|
| Total other income (expense) | (217 | ) | | (103 | ) | | (816 | ) |
| Loss from discontinued operations, net of state income taxes | $ | (2,041 | ) | | $ | (7,593 | ) | | $ | (37,490 | ) |
The total operating and investing cash flows of the non-STACK assets were as follows (in thousands):
| | | | Predecessor | Predecessor |
| | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 | |
| (in thousands) | | January 1, 2018
Through
February 8, 2018 |
| Total operating cash flows of discontinued operations | $ | (6,838 | ) | | $ | 16,166 |
| $ | 2,974 |
|
| Total investing cash flows of discontinued operations | (570 | ) | | (15,950 | ) | (601 | ) |
NOTE 8 — DERIVATIVES
All of our derivatives have the lenders under the Alta Mesa RBL as counterparty, and are collateralized by the security interests thereunder. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes and none have been designated as hedges under GAAP.
The following summarizes the fair value and classification of our derivatives:
|
| | | | | | | | | | | | |
| | | June 30, 2019 |
| Balance sheet location | | Gross fair value of assets | | Gross liabilities offset against assets in the Balance Sheet | | Net fair value of assets presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current assets | | $ | 13,855 |
| | $ | (9,128 | ) | | $ | 4,727 |
|
| Derivatives, long-term assets | | 11,977 |
| | (9,469 | ) | | 2,508 |
|
| Total | | $ | 25,832 |
| | $ | (18,597 | ) | | $ | 7,235 |
|
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of liabilities | | Gross assets offset against liabilities in the Balance Sheet | | Net fair value of liabilities presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current liabilities | | $ | 9,968 |
| | $ | (9,128 | ) | | $ | 840 |
|
| Derivatives, long-term liabilities | | 9,658 |
| | (9,469 | ) | | 189 |
|
| Total | | $ | 19,626 |
| | $ | (18,597 | ) | | $ | 1,029 |
|
|
| | | | | | | | | | | | |
| | | December 31, 2018 |
| Balance sheet location | | Gross fair value of assets | | Gross liabilities offset against assets in the Balance Sheet | | Net fair value of assets presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current assets | | $ | 22,512 |
| | $ | (6,089 | ) | | $ | 16,423 |
|
| Derivatives, long-term assets | | 7,910 |
| | (4,963 | ) | | 2,947 |
|
| Total | | $ | 30,422 |
| | $ | (11,052 | ) | | $ | 19,370 |
|
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of liabilities | | Gross assets offset against liabilities in the Balance Sheet | | Net fair value of liabilities presented in the Balance Sheet |
| | | (in thousands) |
| Derivatives, current liabilities | | $ | 7,799 |
| | $ | (6,089 | ) | | $ | 1,710 |
|
| Derivatives, long-term liabilities | | 5,143 |
| | (4,963 | ) | | 180 |
|
| Total | | $ | 12,942 |
| | $ | (11,052 | ) | | $ | 1,890 |
|
—The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands): FAIR VALUE MEASUREMENTS |
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| Derivatives not designated as hedges | Three Months Ended
June 30, 2019 | | Three Months Ended
June 30, 2018 | | | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Gain (loss) on derivatives - | | | | | | | | | | | |
| Oil | $ | 5,134 |
| | $ | (28,712 | ) | | | $ | (16,535 | ) | | $ | (50,656 | ) | | | $ | 4,796 |
|
| Natural gas | 7,278 |
| | (507 | ) | | | 5,170 |
| | (574 | ) | | | 1,867 |
|
| Total gain (loss) on derivatives | $ | 12,412 |
| | $ | (29,219 | ) | | | $ | (11,365 | ) | | $ | (51,230 | ) | | | $ | 6,663 |
|
Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the ensuing month.
We follow ASC 820, which provides a hierarchy of fair value measurements based onhad 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 reliablefollowing call 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 includeput derivatives at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.June 30, 2019:
|
| | | | | | | | | | | | | | | |
| | | Remaining Volume | | Weighted | | Range |
| Settlement Period and Type of Contract | | in bbls | | Average | | High | | Low |
| 2019 | | |
| | |
| | |
| | |
|
Price Swap Contracts | | 92,000 |
| | $ | 63.03 |
| | $ | 63.03 |
| | $ | 63.03 |
|
| Collar Contracts | | | | | | | | |
| Short Call Options | | 1,361,600 |
| | 66.31 |
| | 75.20 |
| | 56.50 |
|
| Long Put Options | | 1,453,600 |
| | 53.80 |
| | 62.00 |
| | 50.00 |
|
| Short Put Options | | 1,453,600 |
| | 42.72 |
| | 52.00 |
| | 37.50 |
|
| 2020 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Short Call Options | | 1,017,600 |
| | 63.95 |
| | 73.80 |
| | 59.55 |
|
| Long Put Options | | 1,566,600 |
| | 56.81 |
| | 62.50 |
| | 50.00 |
|
| Short Put Options | | 1,566,600 |
| | 42.81 |
| | 50.00 |
| | 37.50 |
|
| 2021 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Short Call Options | | 279,750 |
| | 63.51 |
| | 63.75 |
| | 63.35 |
|
| Long Put Options | | 659,850 |
| | 46.94 |
| | 55.00 |
| | 41.00 |
|
| Short Put Options | | 279,750 |
| | 43.00 |
| | 43.00 |
| | 43.00 |
|
|
| | | | | | | | | | | | | | | |
| | | Remaining Volume | | Weighted | | Range |
| Settlement Period and Type of Contract | | in MMBtu | | Average | | High | | Low |
| 2019 | |
|
| |
|
| |
|
| |
|
|
| Price Swap Contracts | | 7,980,000 |
| | $ | 2.67 |
| | $ | 2.72 |
| | $ | 2.64 |
|
| Basis Swap Contracts | | 9,680,000 |
| | (0.72 | ) | | (0.49 | ) | | (0.93 | ) |
| Collar Contracts | |
|
| |
|
| |
|
| |
|
|
| Short Call Options | | 1,525,000 |
| | 3.19 |
| | 3.20 |
| | 3.17 |
|
| Long Put Options | | 1,525,000 |
| | 2.70 |
| | 2.70 |
| | 2.70 |
|
| Short Put Options | | 1,525,000 |
| | 2.20 |
| | 2.20 |
| | 2.20 |
|
| 2020 | |
|
| |
|
| |
|
| |
|
|
| Price Swap Contracts | | 1,284,000 |
| | 2.54 |
| | 2.54 |
| | 2.54 |
|
| Basis Swap Contracts | | 910,000 |
| | (0.49 | ) | | (0.49 | ) | | (0.50 | ) |
| Collar Contracts | |
|
| |
|
| |
|
| |
|
|
| Short Call Options | | 3,874,500 |
| | 3.19 |
| | 3.69 |
| | 2.77 |
|
| Long Put Options | | 10,749,500 |
| | 2.59 |
| | 3.00 |
| | 2.50 |
|
| Short Put Options | | 9,696,000 |
| | 2.10 |
| | 2.50 |
| | 2.00 |
|
| 2021 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Short Call Options | | 540,000 |
| | 3.25 |
| | 3.25 |
| | 3.25 |
|
| Long Put Options | | 2,790,000 |
| | 2.62 |
| | 2.65 |
| | 2.50 |
|
| Short Put Options | | 2,250,000 |
| | 2.15 |
| | 2.15 |
| | 2.15 |
|
We had the following basis swaps at June 30, 2019:
|
| | | | | | | | | | | | | | |
Total Gas Volumes in MMBtu(1) over Remaining Term | | Reference Price 1 (1) | | Reference Price 2 (1) | | Period | | Weighted Average Spread ($ per MMBtu) |
| 460,000 | | OneOK | | NYMEX Henry Hub | | Jul '19 | | — | | Dec '19 | | $ | (0.93 | ) |
| 7,990,000 | | Tex/OKL Panhandle Eastern Pipeline | | NYMEX Henry Hub | | Jul '19 | | — | | Dec '19 | | (0.70 | ) |
| 910,000 | | Tex/OKL Panhandle Eastern Pipeline | | NYMEX Henry Hub | | Jan '20 | | — | | Mar '20 | | (0.49 | ) |
| 1,230,000 | | San Juan | | NYMEX Henry Hub | | Jul '19 | | — | | Oct '19 | | (0.81 | ) |
________________
| |
| (1) | Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. |
NOTE 9 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
|
| | | | | | | |
| (in thousands) | June 30, 2019 | | December 31, 2018 |
| Accounts payable | $ | 8,871 |
| | $ | 20,200 |
|
| Accruals for capital expenditures | 18,477 |
| | 101,214 |
|
| Revenue and royalties payable | 39,232 |
| | 46,870 |
|
| Accruals for operating expenses | 10,701 |
| | 16,355 |
|
| Accrued interest | 5,642 |
| | 1,784 |
|
| Derivative settlements | 743 |
| | 109 |
|
| Other | 8,028 |
| | 10,532 |
|
| Total accrued liabilities | 82,823 |
| | 176,864 |
|
| Accounts payable and accrued liabilities | $ | 91,694 |
| | $ | 197,064 |
|
NOTE 10 — ASSET RETIREMENT OBLIGATIONS
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Balance, beginning of period | $ | 11,409 |
| | $ | — |
| | | $ | 10,469 |
|
| Liabilities assumed in Business Combination | — |
| | 5,998 |
| | | — |
|
| Liabilities incurred | 634 |
| | 877 |
| | | — |
|
| Liabilities settled | (162 | ) | | (806 | ) | | | (63 | ) |
| Liabilities transferred in sale of properties | — |
| | (20 | ) | | | — |
|
| Revisions to estimates | (9 | ) | | 665 |
| | | 63 |
|
| Accretion expense | 465 |
| | 263 |
| | | 40 |
|
| Balance, end of period | 12,337 |
| | 6,977 |
| | | 10,509 |
|
| Less: Current portion | 44 |
| | 538 |
| | | 33 |
|
| Long-term portion | $ | 12,293 |
| | $ | 6,439 |
| | | $ | 10,476 |
|
NOTE 11 — DEBT
|
| | | | | | | |
| (in thousands) | June 30, 2019 | | December 31, 2018 |
| Alta Mesa RBL | $ | 344,500 |
| | $ | 161,000 |
|
| 2024 Notes | 500,000 |
| | 500,000 |
|
| Unamortized premium on 2024 Notes | 26,662 |
|
| 29,123 |
|
| Total debt, net | 871,162 |
| | 690,123 |
|
| Less: Current portion | 871,162 |
| | — |
|
| Long-term debt, net | $ | — |
| | $ | 690,123 |
|
Alta Mesa RBL
The Alta Mesa RBL has two covenants that are tested quarterly:
a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and
a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0. For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX.
Before July 2020, and possibly as soon as September 30, 2019, we do not expect to satisfy the leverage ratio. We recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements.
At June 30, 2019, inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds.
In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination.
2024 Notes
In connection with our acquisition,the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $476.3$193.8 million at SeptemberJune 30, 2018 (Successor).2019. This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. See Note 11— Long-Term
Scheduled Maturities of Debt Net for information on long-term debt.
|
| | | | |
| Fiscal year | | (in thousands) |
| 2019 | | $ | — |
|
| 2020 | | — |
|
| 2021 | | — |
|
| 2022 | | — |
|
| 2023 | | 344,500 |
|
| Thereafter | | 500,000 |
|
| | | $ | 844,500 |
|
We utilizeBased upon the modified Black-Scholesfactors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than 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 NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices.scheduled maturities shown above. We have classified the inputs used to determine fair valuesreported all of all our oil, natural gas and natural gas liquids derivative contractsdebt as Level 2.current at June 30, 2019.
Oil and natural gas properties are subject to impairment testing and potential impairment write down. During the 2017 Predecessor Period, certain of our oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $2.1 million, resulting in an impairment charge of $1.2 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.
NOTE 12 — COMMITMENTS AND CONTINGENCIES
New additions to asset retirement obligations result from estimations for new or acquired properties. Such estimations of fair value 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. These inputs are classified as Level 3. We recorded $1.7 million, zero and $1.0 million in additions to asset retirement obligations measured at fair valueThere have been no material changes during the Successor Period, thefirst six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.
The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:10-K.
|
| | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| | (in thousands) |
| At September 30, 2018: (Successor) | | | | | | | |
| Financial Assets: | | | | | | | |
| Derivative contracts for oil and natural gas | — | | $ | 5,670 |
| | — | | $ | 5,670 |
|
| Financial Liabilities: | | | | | | | |
| Derivative contracts for oil and natural gas | — | | $ | 47,144 |
| | — | | $ | 47,144 |
|
| At December 31, 2017: (Predecessor) | | | | | | | |
| Financial Assets: | | | | | | | |
| Derivative contracts for oil and natural gas | — | | $ | 4,416 |
| | — | | $ | 4,416 |
|
| Financial Liabilities: | | | | | | | |
| Derivative contracts for oil and natural gas | — | | $ | 24,609 |
| | — | | $ | 24,609 |
|
The amounts above are presented on a gross basis. We will net the value of assets and liabilities with the same counterparty for purposes of presentation in our condensed consolidated balance sheets where master netting agreements are in place. For additional information on derivative contracts, see Note 9 — Derivative Financial Instruments.
NOTE 13 — SIGNIFICANT CONCENTRATIONS
NOTE 9During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. — DERIVATIVE FINANCIAL INSTRUMENTS
Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement.
ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities.
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Three Months Ended
June 30, 2019 | | Three Months Ended
June 30, 2018 | | | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Revenue marketed by ARM on our behalf | $ | 7,703 |
| | $ | 70,601 |
| | | $ | 91,534 |
| | $ | 107,944 |
| | | $ | 28,757 |
|
| | | | | | | | | | | | |
| Marketing and management fees paid to ARM | $ | 476 |
| | $ | — |
| | | $ | 1,137 |
| | $ | — |
| | | $ | — |
|
| Fees paid to ARM for derivative services | 218 |
| | 209 |
| | | 411 |
| | 283 |
| | | 66 |
|
| Total fees paid to ARM | $ | 694 |
| | $ | 209 |
| | | $ | 1,548 |
| | $ | 283 |
| | | $ | 66 |
|
We have entered into forward-swap contractsReceivables from ARM for sales on our behalf were $0.2 million and collar contracts to reduce$38.4 million as of June 30, 2019 and December 31, 2018, respectively, which are reflected in accounts receivable on 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 derivative contracts are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net, 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 derivative contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production equivalent to volumes in gallons (gal) per month. The derivative 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. As of September 30, 2018, we are not a party to any interest rate swap agreements.balance sheets.
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 inbelieve that the fair value of derivative contracts in the condensed 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 condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed 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:
Fair Values of Derivative Contracts:
|
| | | | | | | | | | | | |
| | | September 30, 2018 (Successor) |
| Balance sheet location | | Gross fair value of assets | | Gross liabilities offset against assets in the Balance Sheet | | Net fair value of assets presented in the Balance Sheet |
| | | (in thousands) |
| Derivative financial instruments, current assets | | $ | 2,407 |
| | $ | (2,407 | ) | | $ | — |
|
| Derivative financial instruments, long-term assets | | 3,263 |
| | (3,263 | ) | | — |
|
| Total | | $ | 5,670 |
|
| $ | (5,670 | ) |
| $ | — |
|
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of liabilities | | Gross assets offset against liabilities in the Balance Sheet | | Net fair value of liabilities presented in the Balance Sheet |
| | | (in thousands) |
| Derivative financial instruments, current liabilities | | $ | 36,803 |
| | $ | (2,407 | ) | | $ | 34,396 |
|
| Derivative financial instruments, long-term liabilities | | 10,341 |
| | (3,263 | ) | | 7,078 |
|
| Total | | $ | 47,144 |
|
| $ | (5,670 | ) |
| $ | 41,474 |
|
|
| | | | | | | | | | | | |
| | | December 31, 2017 (Predecessor) |
| Balance sheet location | | Gross fair value of assets | | Gross liabilities offset against assets in the Balance Sheet | | Net fair value of assets presented in the Balance Sheet |
| | | (in thousands) |
| Derivative financial instruments, current assets | | $ | 1,406 |
| | $ | (1,190 | ) | | $ | 216 |
|
| Derivative financial instruments, long-term assets | | 3,010 |
| | (3,002 | ) | | 8 |
|
| Total | | $ | 4,416 |
|
| $ | (4,192 | ) |
| $ | 224 |
|
|
| | | | | | | | | | | | |
| Balance sheet location | | Gross fair value of liabilities | | Gross assets offset against liabilities in the Balance Sheet | | Net fair value of liabilities presented in the Balance Sheet |
| | | (in thousands) |
| Derivative financial instruments, current liabilities | | $ | 20,493 |
| | $ | (1,190 | ) | | $ | 19,303 |
|
| Derivative financial instruments, long-term liabilities | | 4,116 |
| | (3,002 | ) | | 1,114 |
|
| Total | | $ | 24,609 |
|
| $ | (4,192 | ) |
| $ | 20,417 |
|
The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations (in thousands):
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| Derivatives not | Three | | | Three | | February 9, 2018 | | | January 1, 2018 | | Nine |
| designated as hedging | Months Ended | | | Months Ended | | Through | | | Through | | Months Ended |
| instruments under ASC 815 | September 30, 2018 | | | September 30, 2017 | | September 30, 2018 | | | February 8, 2018 | | September 30, 2017 |
| Gain (loss) on derivative contracts | | | | | | | | | | |
| Oil commodity contracts | $ | (12,339 | ) | | | $ | (10,873 | ) | | $ | (63,630 | ) | | | $ | 5,431 |
| | $ | 31,665 |
|
| Natural gas commodity contracts | 1,127 |
| | | 1,035 |
| | 553 |
| | | 1,867 |
| | 6,763 |
|
| Natural gas liquids commodity contracts | — |
| | | (630 | ) | | — |
| | | — |
| | (404 | ) |
| Total gain (loss) on derivative contracts | $ | (11,212 | ) | | | $ | (10,468 | ) | | $ | (63,077 | ) |
| | $ | 7,298 |
|
| $ | 38,024 |
|
The Company periodically monitors the creditworthiness of its counterparties. Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, under certain circumstances, 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 described in Note 11 — Long-Term Debt, Net.
If a counterparty were to default on payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the derivative could be lost. The value of our derivative financial instruments would be impacted.
We had the following open derivative contracts for crude oil at September 30, 2018:
OIL DERIVATIVE CONTRACTS
|
| | | | | | | | | | | | | | | |
| | | Volume in bbls | | Weighted Average | | Range |
| Settlement Period and Type of Contract | | | | High | | Low |
| 2018 | | |
| | |
| | |
| | |
|
Price Swap Contracts | | 552,000 |
| | $ | 53.55 |
| | $ | 61.26 |
| | $ | 50.27 |
|
| Collar Contracts | | | | | | | | |
| Short Call Options | | 552,000 |
| | 61.28 |
| | 64.60 |
| | 60.50 |
|
| Long Put Options | | 552,000 |
| | 51.67 |
| | 60.00 |
| | 50.00 |
|
| Short Put Options | | 552,000 |
| | 42.08 |
| | 52.50 |
| | 40.00 |
|
| 2019 | | | | | | | | |
Price Swap Contracts | | 182,500 |
| | 63.03 |
| | 63.03 |
| | 63.03 |
|
| Collar Contracts | | | | | | | | |
| Short Call Options | | 2,701,000 |
| | 66.31 |
| | 75.20 |
| | 56.50 |
|
| Long Put Options | | 2,883,500 |
| | 53.80 |
| | 62.00 |
| | 50.00 |
|
| Short Put Options | | 2,883,500 |
| | 42.72 |
| | 52.00 |
| | 37.50 |
|
| 2020 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Short Call Options | | 366,000 |
| | 67.00 |
| | 73.80 |
| | 60.20 |
|
| Long Put Options | | 1,317,600 |
| | 56.46 |
| | 62.50 |
| | 50.00 |
|
| Short Put Options | | 1,317,600 |
| | 45.83 |
| | 50.00 |
| | 40.00 |
|
We had the following open derivative contracts for natural gas at September 30, 2018:
NATURAL GAS DERIVATIVE CONTRACTS
|
| | | | | | | | | | | | | | | |
| | | Volume in MMBtu | | Weighted Average | | Range |
| Settlement Period and Type of Contract | | | | High | | Low |
| 2018 | | |
| | |
| | |
| | |
|
Price Swap Contracts | | 1,842,500 |
| | $ | 2.95 |
| | $ | 3.09 |
| | $ | 2.75 |
|
| Collar Contracts | | | | | | | | |
| Short Call Options | | 1,832,500 |
| | 3.36 |
| | 3.75 |
| | 3.14 |
|
| Long Put Options | | 1,527,500 |
| | 2.89 |
| | 2.90 |
| | 2.75 |
|
| Short Put Options | | 610,000 |
| | 2.40 |
| | 2.40 |
| | 2.40 |
|
| 2019 | | | | | | | | |
Price Swap Contracts | | 10,905,000 |
| | 2.69 |
| | 3.09 |
| | 2.64 |
|
| Collar Contracts | | | | | | | | |
| Short Call Options | | 4,000,000 |
| | 3.31 |
| | 3.75 |
| | 3.17 |
|
| Long Put Options | | 3,550,000 |
| | 2.81 |
| | 2.90 |
| | 2.70 |
|
| Short Put Options | | 2,425,000 |
| | 2.27 |
| | 2.40 |
| | 2.20 |
|
| 2020 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Short Call Options | | 2,275,000 |
| | 3.19 |
| | 3.20 |
| | 3.17 |
|
| Long Put Options | | 9,150,000 |
| | 2.57 |
| | 2.70 |
| | 2.50 |
|
| Short Put Options | | 9,150,000 |
| | 2.07 |
| | 2.20 |
| | 2.00 |
|
| 2021 | | | | | | | | |
| Collar Contracts | | | | | | | | |
| Long Put Options | | 2,250,000 |
| | 2.65 |
| | 2.65 |
| | 2.65 |
|
| Short Put Options | | 2,250,000 |
| | 2.15 |
| | 2.15 |
| | 2.15 |
|
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 index or may reflect a mix of positions settling on various combinations of these benchmarks.
We had the following open financial basis swaps at September 30, 2018:
NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS
|
| | | | | | | | | | | | | | |
Volume in MMBtu(1) | | Reference Price 1 (1) | | Reference Price 2 (1) | | Period | | Weighted Average Spread ($ per MMBtu) |
| 460,000 | | OneOK | | NYMEX Henry Hub | | Jul '19 | | — | | Dec '19 | | $ | (0.93 | ) |
| 4,445,000 | | Tex/OKL Panhandle Eastern Pipeline | | NYMEX Henry Hub | | Oct '18 | | — | | Dec '18 | | (0.63 | ) |
| 17,950,000 | | Tex/OKL Panhandle Eastern Pipeline | | NYMEX Henry Hub | | Jan '19 | | — | | Dec '19 | | (0.68 | ) |
| 910,000 | | Tex/OKL Panhandle Eastern Pipeline | | NYMEX Henry Hub | | Jan '20 | | — | | Mar '20 | | (0.49 | ) |
| 152,500 | | San Juan | | NYMEX Henry Hub | | Nov '18 | | — | | Dec '18 | | (0.47 | ) |
| 2,365,000 | | San Juan | | NYMEX Henry Hub | | Jan '19 | | — | | Oct '19 | | (0.78 | ) |
_________________
| |
(1) | Represents short swaps that fix the basis differentials between OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.
|
OIL BASIS SWAP DERIVATIVE CONTRACTS
|
| | | | | | | | | | | | | | |
Volume in bbl (1) | | Reference Price 1 (1) | | Reference Price 2 (1) | | Period | | Weighted Average Spread ($ per bbl) |
| 552,000 | | CMA Oil | | WTI | | Oct '18 | | — | | Dec '18 | | $ | (0.54 | ) |
_________________
| |
(1) | Represents basis swaps for the basis differentials between NYMEX CMA (Calendar Monthly Average) Roll that reconcile the trade month versus the delivery month for physical contract pricing and West Texas Intermediate (“WTI”). |
NOTE 10 — ASSET RETIREMENT OBLIGATIONS
A summary of the changes in asset retirement obligations is included in the table below (in thousands):
|
| | | |
| | 2018 |
| Balance, as of January 1 (Predecessor) | $ | 10,469 |
|
| Liabilities settled | (63 | ) |
| Revisions to estimates | 63 |
|
| Accretion expense | 39 |
|
| Balance, as of February 8 (Predecessor) | $ | 10,508 |
|
| | |
| Balance, as of February 9 (Successor) | $ | — |
|
| Liabilities assumed from Business Combination | 5,998 |
|
| Liabilities incurred | 1,689 |
|
| Liabilities settled | (1,249 | ) |
| Liabilities transferred in sale of properties | (20 | ) |
Revisions to estimates (1) | 3,562 |
|
| Accretion expense | 489 |
|
| Balance, as of September 30 (Successor) | 10,469 |
|
| Less: Current portion | 1,300 |
|
| Long-term portion | $ | 9,169 |
|
(1)The total revisions included $3.0 million related to additions to property, plant and equipment for the Successor Period.
NOTE 11 — LONG-TERM DEBT, NET
Long-term debt, net consisted of the following (in thousands):
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | September 30,
2018 | | | December 31, 2017 |
| Senior secured revolving credit facility | $ | 80,000 |
| | | $ | 117,065 |
|
| 7.875% senior unsecured notes due 2024 | 500,000 |
| | | 500,000 |
|
| Unamortized premium on senior unsecured notes | 30,354 |
| | | — |
|
| Unamortized deferred financing costs | — |
| | | (9,625 | ) |
| Total long-term debt, net | $ | 610,354 |
|
| | $ | 607,440 |
|
Senior Secured Revolving Credit Facility (Successor). In connection with the consummation of the Business Combination, all indebtedness at that time under the senior secured revolving credit facility was repaid in full. On February 9, 2018, and in connection with the closing of the AM Contribution Agreement (as described in Note 5), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, our borrowing base was increased to $400.0 million. This borrowing base was reaffirmed by the lenders subsequent to September 30, 2018. The next scheduled redetermination will occur in April 2019, at which time the borrowing base may be increased, lowered or stay the same. The Eighth A&R credit facility does not permit us to borrow funds if, at the time of such borrowing, we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of September 30, 2018, we had $80.0 million of borrowings outstanding under the Eighth A&R credit facility and had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $298.1 million remaining available for future use.
The principal amounts borrowed are payable on the maturity date of February 9, 2023. We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.00%. Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00%, plus a margin ranging from 1.00% to 2.00%.
The amounts outstanding under the Eighth A&R credit facility are secured by the first priority liens on substantially all of the Company’s, and its material operating subsidiaries’, oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged collateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.
The Eighth A&R credit facility, as amended effective August 13, 2018, 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 in excess of specific amounts, enter into or be party to hedge agreements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and general and administrative expenses (“G&A”) incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the tax receivable agreement.
The Eighth A&R credit facility also requires us to maintain the following two financial ratios:
a current ratio, subject to various adjustments as defined in the Eighth A&R credit facility, tested quarterly, commencing with the fiscal quarter ended June 30, 2018, 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 June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX annualized by multiplying EBITDAX for the period of (a) the fiscal quarter ended June 30, 2018 times 4, (b) the two fiscal quarter periods ended September 30, 2018 times 2 (c) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and
(d) for each fiscal quarter on or after March 31, 2019, EBITDAX for the four-fiscal quarter period then ended, of not greater than 4.0 to 1.0.
As of September 30, 2018, we were in compliance with the financial ratios described above.
Senior Secured Revolving Credit Facility (Predecessor). As of December 31, 2017, the Company had $117.1 million of borrowings outstanding. At the date of the Business Combination, the outstanding balance under our credit facility was paid off.
Senior Unsecured Notes. We have $500.0 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017.
The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year. 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 senior notes for an amount of cash not greater than the net cash proceeds from certain equity offerings at a 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 senior 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 senior notes for cash at a redemption price equal to 100% of their principal amount of the senior 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 senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior 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 senior 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 senior 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 obligationsloss of any of our subsidiaries that do not guarantee the senior notes.
The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stockcustomers, 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 senior 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 the purchase. The closing of the Business Combination with AMR did not constitute a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in AMH GP. See Note 5 — Business Combination to the consolidated condensed financial statements for further detail.
The indenture contains customary events of default, including:
default in any payment of interest on the senior notes when due, continued for 30 days;
default in the payment of principal or premium, if any, on the senior notes when due;
failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture;
default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries;
certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and
failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20 million.
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.
As of September 30, 2018, we were in compliance with the indentures governing the senior notes.
Bond Premium (Successor). As discussed in Note 5, the fair value of our senior notes as of the acquisition date was $533.6 million. The bond premium of $33.6 million is being amortized over the respective term of the senior notes. The bond premium amortization recognized in interest expense was $1.2 million and $3.3 million for the three months ended September 30, 2018 (Successor) and the Successor Period, respectively. The unamortized bond premium related to the senior notes is included asmarketing agent ARM, would not have a component of long-term debt in the condensed consolidated balance sheet as of September 30, 2018.
Deferred financing costs. As of December 31, 2017 (Predecessor), we had $11.4 million of unamortized deferred financing costs related to both our senior secured notes and the Eighth A&R credit facility. As a result of the Business Combination, our unamortized deferred financing costs were adjusted to a fair value of zero at February 9, 2018. During the Successor Period, we incurred additional deferred financing costs related to the Eighth A&R credit facility of $1.4 million. These costs are reflected as deferred financing costs, net in other noncurrent assets in the condensed consolidated balance sheets as of September 30, 2018 (Successor). The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations. For the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), the amortization of deferred financing costs was $0.1 million and $0.7 million, respectively. For the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0.2 million, $0.2 million and $2.2 million, respectively.
NOTE 12 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the details of accounts payable and accrued liabilities (in thousands):
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | September 30,
2018 | | | December 31,
2017 |
| Accruals for capital expenditures | $ | 83,687 |
| | | $ | 48,771 |
|
| Revenues and royalties payable | 44,626 |
| | | 29,514 |
|
| Accruals for operating expenses/taxes | 8,156 |
| | | 14,632 |
|
| Accrued interest | 11,651 |
| | | 2,587 |
|
| Derivative settlement payable | 4,593 |
| | | 2,106 |
|
| Other | 3,408 |
| | | 4,301 |
|
| Total accrued liabilities | 156,121 |
|
| | 101,911 |
|
| Accounts payable | 71,018 |
| | | 68,578 |
|
| Accounts payable and accrued liabilities | $ | 227,139 |
|
| | $ | 170,489 |
|
NOTE 13 — COMMITMENTS AND CONTINGENCIES
Commitments
We lease office space and certain field equipment such as compressors, under long-term operating lease agreements. On April 1, 2018, we amended the lease agreement for our corporate headquarters located in Houston, Texas. The amended lease agreement provides for additional office space and extends the original lease term through April 2028. Due to the amendment, we have additional lease commitment obligations of approximately $17.6 million through April 2028. Any initial rent-free months are amortized over the life of the lease.
The Company has entered into certain firm transportation contracts that extend through 2028. At September 30, 2018, the future minimum commitments related to these contracts were approximately $5.7 million a year.
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 condensed consolidated financial statements at September 30, 2018.
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 (Predecessor). On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our former 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 claimed 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. 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. In connection with the Business Combination, the liability was included in the distribution of our non-STACK assets to the AM Contributor.
On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP and Alta Mesa Services, LP, each a wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleged that the AMH Parties made improper post production deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. As of December 31, 2017, we had accruals of approximately $4.7 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets and in G&A in our condensed consolidated statements of operations as a result of this litigation. During January 2018, approximately $4.7 million was paid to fund the settlement. On March 12, 2018, the class settlement was approved by the Court.
Litigation (Successor). On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy and unjust enrichment/constructive trust against all defendants, including us. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves.
Other contingencies. We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes 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 litigationus because alternative purchasers 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 was intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Company accelerated the vesting and payment of all outstanding PARs in connection with the Business Combination with AMR as described in Note
5. The value of the PARs that vested was approximately $10.9 million and such amount was recorded in G&A in the Successor Period. Following the closing of the Business Combination, the Plan was terminated.
Nonqualified Deferred Compensation. In 2013, we established a nonqualified deferred compensation plan, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”). The Retirement Plan was intended to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. In connection with the Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in G&A in the Successor Period. readily available.
NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of 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. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Declines in oil and/or natural gas prices 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. 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 9 — Derivative Financial Instruments for further details on derivatives.
NOTE 15 — PARTNERS’ CAPITAL
Management and Control: Our Seventh Amended and Restated Agreement of Limited Partnership (the “Seventh Amended Partnership Agreement”) currently provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by AMH GP referred to as “GP Units”. AMH GP owns all the GP Units and in connection with the Business Combination, SRII Opco owns all the LP Units.
As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP. The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP.
SRII Opco is the sole owner of Class A Units and owns 90% of the Class B Units. Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company, and HPS Investment Partners, LLC, a Delaware limited liability company, own an aggregate 10% of the Class B Units. AMH GP’s Board of Directors are selected by the Class B members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement.
The Seventh Amended Partnership Agreement specifies the manner in which we will make cash distribution to our partners. When AMH GP so directs, we shall make distributions of Net Cash Flow (as defined in the Seventh Amended Partnership Agreement) to the limited partner.
NOTE 16 —EQUITY-BASED COMPENSATION (Successor)
Following the closing of the Business Combination,Stock compensation expense allocated to us by AMR adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of 50,000,000 shares of AMR’s Class A Common Stock were reserved for issuance under the LTIP. The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in AMR’s Class A Common Stock. Priorpursuant to the Business Combination, we did not have anyits equity-based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards have been made to various employees of the Company since February 9, 2018. During the Successor Period, we recognized non-cash stock-based compensation expense of $6.7 million resulting from stock options, restricted stock, and RSUs awards granted to our employees, which is included in general and administrative expense in the accompanying condensed consolidated statements of operations. Historical amounts may not be representative of future amountsprograms was as the value of future awards may vary from historical amounts.
We recognize compensation expense on a straight-line basis for service-based grants to our employees over the vesting period. The fair value of restricted stock awards and performance-based restricted stock units is determined based on the estimated fair market value of AMR’s Class A Common Stock on the date of grant. As provided in ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, the Company has elected to recognize actual forfeitures as they occur.
Stock options. Options that have been granted under the LTIP expire seven years from the grant date and generally vest in one-third increments each year on the anniversary date following the date of grant, based on continued employment. The exercise price for an option granted under the LTIP may not be below the fair value of AMR’s Class A Common Stock on the grant date.
Information about outstanding stock options is summarized in the table below:
|
| | | | | | | | | | | | | |
| | Successor |
| | Stock Options | | Weighted Average Grant - Date Fair Value | | Weighted Average Remaining Term (in years) | | Aggregate Intrinsic Value (in thousands) |
| Outstanding as of February 9, 2018 | — |
| | $ | — |
| | — |
| | |
| Granted | 4,704,433 |
| | 4.45 |
| | — |
| | |
| Exercised | — |
| | — |
| | — |
| | |
| Forfeited or expired | (94,693 | ) | | 4.52 |
| | — |
| | |
| Outstanding as of September 30, 2018 | 4,609,740 |
| | $ | 4.44 |
| | 6.4 |
| | $ | — |
|
| Exercisable as of September 30, 2018 | — |
| | $ | — |
| | — |
| | $ | — |
|
Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable three-year vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
The following summarizes the assumptions used to determine the fair value of those options:
follows:
|
| | |
| Successor |
| February 9, 2018 Through September 30, 2018 |
Expected term (in years) | 4.5 |
|
Expected stock volatility | 64.6 | % |
Dividend yield | — |
|
Risk-free interest rate | 2.4 | % |
|
| | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Three Months Ended
June 30, 2019 | | Three Months Ended
June 30, 2018 | | | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Stock options | $ | 744 |
| | $ | 1,606 |
| | | $ | 1,535 |
| | $ | 2,628 |
| | | $ | — |
|
| Restricted stock awards | 563 |
| | 871 |
| | | 1,425 |
| | 1,412 |
| | | — |
|
| Performance-based restricted stock units | 89 |
| | 1,144 |
| | | 97 |
| | 2,349 |
| | | — |
|
| Total compensation expense | $ | 1,396 |
| | $ | 3,621 |
| | | $ | 3,057 |
| | $ | 6,389 |
| | | $ | — |
|
As of September 30, 2018, there was $16.2 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.4 years.
Restricted stock. Restricted stock granted to employees generally vests in one-third increments each year on the anniversary date following the date of grant, based on continued employment. Prior to vesting, no dividends are paid and the shares may not be traded.
The following table provides information about restricted stock awards granted during the Successor Period:
|
| | | | | | |
| | Successor |
| | Restricted Stock Awards | | Weighted Average Grant Date Fair Value per share |
| Outstanding as of February 9, 2018 | — |
| | $ | — |
|
| Granted | 1,658,756 |
| | 7.77 |
|
| Vested | — |
| | — |
|
| Forfeited or expired | (42,086 | ) | | 8.74 |
|
| Outstanding as of September 30, 2018 | 1,616,670 |
|
| $ | 7.75 |
|
Compensation cost for restricted shares is based upon the grant-date market value of the award, recognized ratably over the applicable three-year vesting period, subject to the employee’s continued service. Unrecognized compensation cost related to unvested restricted shares at September 30, 2018 was $10.1 million, which the Company expects to recognize over a weighted average remaining period of 2.5 years.
Restricted stock units. The Company also grants performance-basedPerformance-based restricted stock units (“PSUs”) to key employees under the LTIP. PSUs granted during the period willissued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year.year (“2020 tranche”). The number of PSUs vesting each year will beare based on the achievement of annual company-specifiedcompany-specific performance goals and objectivesobligations applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest can range from 0% to 200% of the target grantgrowth applicable to each vesting period. For accounting purposes,The performance goals set for the Company2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted.
The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will only recognize PSUs granted whenbe recognized as expense over the specifiedremainder of 2019, subject to continued employment.
No performance thresholdstargets have yet been established for future periodsthe 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established. For PSUs grantedestablished and probability of attainment can be measured.
NOTE 15 — RELATED PARTY TRANSACTIONS
As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables.
As of December 31, 2018, we had a payable to AMR of $0.5 million which was settled during the second quarter of 2019.
David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates was his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $28,000 for the period February 9, 2018 to Septemberthrough June 30, 2018, onlyand the performance goalsPredecessor Period, respectively. These amounts are recorded in general and objectives foradministrative expenses.
David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860, $929,428 and $28,874 during the six months ended June 30, 2019, the period February 9, 2018 have been establishedthrough June 30, 2018, and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to date. Those 2018 performance goals are related toAMH. Mr. McClure separated from the Company achieving a specified level of EBITDAX for the period ended December 31, 2018.in February 2019.
The following summary provides information about the target number of PSUs granted during the Successor Period:Bayou City Agreement
|
| | | | | | | |
| | Successor |
| | PSUs | | Weighted Average Grant - Date Fair Value per unit |
| Outstanding as of February 9, 2018 | — |
| | $ | — |
|
| Granted | 781,200 |
| | 8.69 |
|
| Vested | — |
| | — |
|
| Forfeited or expired | (4,174 | ) | | 8.45 |
|
| Outstanding as of September 30, 2018 | 777,026 |
| — |
| $ | 8.69 |
|
As of September 30, 2018, there was no material unrecognized compensation cost related to the unvested PSUs.
NOTE 17 — RELATED PARTY TRANSACTIONS
OnIn January 13, 2016, Alta Mesa’sour wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “Joint Development Agreement”“JDA”), with BCE-STACK Development LLC (“BCE”),BCE, a fund advised by Bayou City, to fund a portion of Alta Mesa’sour drilling operations and to allow Alta Mesaus to accelerate development of our STACK acreage. The Joint Development Agreement, as amended, establishesJDA established a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells.
Pursuant to the terms and provisions of the Joint Development Agreement,JDA, BCE committed to fund 100% of Alta Mesa’sour working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche, subject to modifications or adjustments proposed and approved by the parties.tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, Alta Mesawe and BCE will each bear its
our respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our former directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the Joint Development Agreement. As of SeptemberJDA. Through June 30, 2018, 552019, 61 joint wells have been drilled or spudded. As of SeptemberAt June 30, 2018 (Successor),2019 and December 31, 2017 (Predecessor), $16.92018, $4.0 million and $23.4$9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the Joint Development AgreementJDA were included as “Advances from related party” in our condensed consolidated balance sheets. BCE may request refunds of certain advances from timeAt June 30, 2019, there were no funded horizontal wells in progress, and we do not expect any wells to time if funded wells previously on the drilling schedule were subsequently removed.
On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with Kingfisher. The Gas Gathering and Processing Agreement was subsequently amended on February 3, 2017, effective as of December 1, 2016, and thereafter amended on June 29, 2018, effective as of April 1, 2018. The recent amendmentbe developed in 2019 pursuant to the Gas GatheringJDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and Processing Agreement impacts our net NGL production volumes but will not impact our consolidated financial statements.
Effective June 1, 2018, we entered into a Marketing Services Agreement with ARM Energy Management, LLC (“AEM”) pursuantintend to which AEM markets our oil, natural gas and natural gas liquids and sells them under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location and quality taken into account. AEM remits monthly collections on these sales to us, and receives a marketing fee. In addition, AEM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system for an asset management fee. The AM Contributor owns less than 10% of AEM. For the period from June 1, 2018 to September 30, 2018, we paid AEM $0.8 million for our share of the marketing fees.vigorously defend ourselves.
NOTE 18 — SUBSIDIARY GUARANTORS
All of our wholly owned subsidiaries are guarantors under the terms of the senior notes and the Eighth A&R credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company to these subsidiaries, we have 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 by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries. There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.
NOTE 19—SUBSEQUENT EVENTS
Sale of Produced Water Assets
Effective November 9, 2018, the Company sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC, a related party and wholly owned subsidiary of our parent, AMR, for a total purchase price of $90.0 million in cash, subject to normal acquisition adjustments. At
September 30, 2018, the net book value of long-lived assets associated with these operations totaled $86.9 million. In conjunction with the sale, the Company entered into a new fifteen-year water gathering and disposal agreement with Kingfisher Midstream.
ITEMItem 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 condensed 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, 2017 (“2017 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, our ability to continue as a going concern, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed in “Cautionary Statement Regarding Forward-Looking Statements,”Statements” at the beginning of this Quarterly Report and in our 2017 Annual Report, particularly in the sectionsections titled “Risk Factors,”Factors” in this Quarterly Report and in our 2018 10-K, 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
Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) isWe are an independent exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin CanadianSTACK. We generate revenue principally by the production and Kingfisher County (“STACK”).sale of oil, natural gas and NGLs. We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.
As a result of Septemberthe Business Combination, our identifiable assets acquired and liabilities assumed by our parent company were recorded at their estimated fair values at February 9, 2018 and were pushed down to us. As a result, our financial statements and certain footnote presentations separate our presentations into two distinct periods, the period before the consummation of the Business Combination (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. Accordingly, the period January 1, 2018 to February 8, 2018 is referred to as the Predecessor Period.
We distributed our non-STACK oil and gas assets and liabilities to High Mesa in connection with the closing of the Business Combination. We report the non-STACK oil and gas assets and liabilities as discontinued operations during the Predecessor Period.
As of June 30, 2018,2019, we have assembled a highly contiguous position of approximately 134,000130,000 net acres in the up-dip, naturally-fractured oil portion of the STACK primarily in eastern Kingfisher County and south-eastern Major County,counties in Oklahoma. Our drilling locations primarily target the Osage, Meramec and Oswego formations. After the Business Combination, we conducted development activities using a spacing array of 6 to 10 wells per section and running up to 9 rigs at the peak activity level. In late 2018, our production across the acreage evidenced that the well spacing was not delivering the well level production that we expected. During January 2019, we suspended our development program to allow our new management team to conduct a full operational and economic review. We restarted our development program in March 2019 with a less dense spacing pattern of up to five wells per section. In addition, we have worked to improve our economic returns by reducing well costs, general and administrative expense and other operating expense.
We have operated 2 rigs since restarting the program, however following the redetermination of the borrowing base of the Alta Mesa RBL in August 2019, we have decided to operate 1 rig starting in September. We will continue to acquire acreage within and adjacent to our acreage footprint with the goal of operating the drilling, completion and production operations in such locations. At present, we are operating nine horizontal drilling rigs in the STACK. evaluate how much, if any, development is appropriate going forward.
Additional information relating to the acquisition of Alta Mesa by Alta Mesa Resources, Inc. and certain other transactions that occurred on February 9, 2018, may be found in Note 5 — Business Combination of the Notes to Condensed Consolidated Financial Statements. Immediately prior to the closing of the business combination described in Note 5, we also distributed our non-STACK assets and related liabilities to High Mesa Holdings, LP (the “AM Contributor”), which is more fully described in Note 7 — Discontinued Operations (Predecessor) of the Notes to Condensed Consolidated Financial Statements, relating to discontinued operations.
Outlook, Market Conditions and Commodity Prices
Our revenue, profitability and future growth rate depend on many factors, particularly the prices of oil, natural gas and natural gas liquids,NGLs, which are beyond our control. The success of our business is significantly affected by the price of oil due to its weighting in our current focus on development of oil reserves and exploration for oil.production profile.
Factors affecting oil prices include worldwide economic conditions; geopolitical activities in various regions of the world; worldwide supply and demand conditions; weather conditions; actions taken by the Organization of Petroleum Exporting Countries; and the value of the U.S. dollar in international currency markets. Commodity prices remain unpredictable and it is uncertain whether the increase in market prices experienced in recent months will be sustained. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital expenditures, production volumes or revenues. IfIn the event that oil, natural gas and NGLs prices were to significantly decrease, such decreases 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 ourthe borrowing capacity under the Eighth A&R credit facility. Alta Mesa RBL.
Key performance indicators
During 2019, our board of directors has established the following operating measures as key performance indicators for executive management compensation and the Company as a whole:
Production;
General and administrative costs (excluding strategic costs);
Lease operating expense;
Well drilling and completion costs; and
Adjusted EBITDAX.
We will focus on measuring our performance against baseline and prior year comparable periods during this and future filings.
The following tables set forthCompany’s management believes Adjusted EBITDAX is useful because it allows users to more effectively evaluate our operating performance, compare the average New York Mercantile Exchangeresults of our operations from period to period and against our peers without regard to our financing methods or capital structure and because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures. Adjusted EBITDAX should not be considered as an alternative to our net income (loss), operating income (loss) or other performance measures derived in accordance with GAAP and may not be comparable to similarly titled measures in other companies’ reports.
Going concern
Our present level of indebtedness and the current commodity price environment present challenges to our ability to comply with the covenants under our debt agreements. As a result of our updated forecasted production levels and pressures created by lower commodity prices, for oil and natural gas forin the three and nine months endedabsence of one or more deleveraging transactions, we do not anticipate maintaining compliance with the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 20182019. Also, in August 2019 the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reduced to $200 million. As such, we are required to repay the $162.4 million of combined excess of our borrowings and letters of credit outstanding ratably over five months in $32.5 million installments, which will have an adverse impact on our liquidity. The first payment is due in September 2019. If we are unable to make repayment of this amount, we will be in default under the Alta Mesa RBL. As a consequence of both reduced operating cash flow and a reduced borrowing base, we may have limited ability to obtain the capital necessary to conduct our operations at desired levels. Our general partner’s board of directors and our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If an event of default occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an acceleration of the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. We currently anticipate that our indebtedness will accelerate prior to July 1, 2020 and therefore, have reported all of our debt as current at June 30 2019. 2017:
|
| | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| | 2018 | | 2017 | | Change | | % |
| Average NYMEX daily prices: | | | | | | | |
| Oil (per bbl) | $ | 69.43 |
| | $ | 48.20 |
| | $ | 21.23 |
| | 44 | % |
| Natural gas (per MMBtu) | $ | 2.87 |
| | $ | 2.95 |
| | $ | (0.08 | ) | | (3 | )% |
|
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, |
| | 2018 | | 2017 | | Change | | % |
| Average NYMEX daily prices: | | | | | | | |
| Oil (per bbl) | $ | 66.73 |
| | $ | 49.36 |
| | $ | 17.37 |
| | 35 | % |
| Natural gas (per MMBtu) | $ | 2.85 |
| | $ | 3.05 |
| | $ | (0.20 | ) | | (7 | )% |
If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court. We may also conclude it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are otherwise unable to reach an agreement with our creditors. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims, including our secured and unsecured creditors, will receive substantially less than the amount of their claims. Our derivative contracts are reported at fair value on our condensed consolidated balance sheets and are sensitive to changes in the price of oil, natural gas and NGLs. ChangesRisk Factors described in our derivative assets and liabilities are reported in our condensed consolidated statements of operations as “Gain (loss) on derivative contracts”, which include both the non-cash increase or decrease in the fair value of derivative contracts, as well as the effect of cash settlements of derivative contracts during the period. For the three months ended September 30, 2018 (Successor), we recognized a net loss on our derivative contracts of $11.2 million, which includes $13.9 million in cash settlements paid for derivative contracts. We recognized a net loss on our derivative contracts of $63.1 million in the Successor Period, which includes $32.8 million in cash settlements paid for derivative contracts. 10-K contain important information.
Derivatives
The objective of our hedging program is to produce, over time, relative revenue stability. However, in the short term,short-term, both settlements and fair value changes in our derivative contractsderivatives can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and natural gas prices. Our derivatives are reported at fair value and are sensitive to changes in the price of oil and gas. Changes in derivatives are reported as gain (loss) on derivatives, which include both the unrealized increase and decrease in their fair value, as well as the effect of realized settlements during the period. For the six months ended June 30, 2019, we recognized a net loss on our derivatives of $11.4 million, which includes $0.9 million in cash received upon derivative settlements.
Operations Update
Our STACK properties consist largely of contiguous leased acreage in Kingfisher County and Major County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK. This 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.
During the three months ended September 30, 2018, we brought 53 operated horizontal wells on production of which two were funded through our joint development agreement with BCE-STACK Development LLC (“BCE”). We had 38 operated horizontal wells in progress as of September 30, 2018, of which three were funded through our joint development agreement with BCE. As of November 1, 2018, 16 of the 38 operated horizontal wells in progress as of September 30, 2018 were on production.
As of September 30, 2018, we had eight drilling rigs concurrently operating in the STACK focused on drilling wells targeting oil production and/or Company-owned saltwater disposal wells. At the beginning of November 2018, we had nine 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 formations. Impairments
Production
In late fourth quarter of 2018, the combination of depressed prevailing oil and gas prices, changes to assumed spacing in conjunction with evolving views on the viability of multiple benches and reduced individual well expectations resulted in impairment charges of $2.0 billion to our proved and unproved oil and gas properties during the quarter ended December 31, 2018. Individual well expectations were impacted by reductions in estimated reserve recovery of original oil and gas in place. In the future, we may recognize further impairments of proved and unproved oil and gas properties if commodity prices decline from current levels, incremental downward revisions to production forecasts occur or operating costs increase. Prolonged low commodity prices may also result in additional impairments of other assets and could cause us to delay or abandon anticipated development activities.
Factors affecting future performance
The primary factors affecting our STACK assets wasproduction levels, which may be interrelated, are current commodity prices, capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, our wells have significant natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped resources, well recompletions and other enhanced recovery methods. Sustaining our production levels or our future growth will depend on our ability to continue to develop reserves, including our ability to fund such development. Our ability to add reserves through drilling and other development techniques is dependent on current market conditions and 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 revenue and, as follows:
|
| | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Successor | | | Predecessor |
| | Three | | | Three | | February 9, 2018 | | | January 1, 2018 | | Nine |
| | Months Ended | | | Months Ended | | Through | | | Through | | Months Ended |
| | September 30, 2018 | | | September 30, 2017 | | September 30, 2018 | | | February 8, 2018 | | September 30, 2017 |
| Average, net to our interest (MBOE/d) | 33.4 |
| | | 20.4 |
| | 28.5 |
| | | 23.4 |
| | 20.1 |
|
| | | | | | | | | | | | |
| Percentage of oil | 50 | % | | | 50 | % | | 50 | % | | | 54 | % | | 50 | % |
| Percentage of NGLs | 22 | % | | | 17 | % | | 22 | % | | | 17 | % | | 17 | % |
| Percentage of oil and NGLs | 72 | % | | | 67 | % | | 72 | % | | | 71 | % | | 67 | % |
As described in Note 19, onNovember 9, 2018, the Company sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC, a related party and wholly owned subsidiary of our parent, AMR, for a total purchase price of $90.0 million in cash, subject to normal acquisition adjustments. In conjunction with the sale, the Company entered into a new fifteen-year water gathering and disposal agreement with Kingfisher Midstream.
Results of Operations
For the Three Months Ended SeptemberJune 30, 2018 (Successor)2019 (“Second Quarter 2019”) Compared to the Three Months Ended SeptemberJune 30, 2017 (Predecessor)2018 (“Second Quarter 2018”).
The tables included below set forth financial information for the three months ended September 30, 2018 (Successor) and September 30, 2017 (Predecessor). The amounts below exclude operating results related to discontinued operations.
RevenuesRevenue
Our oil, natural gas and NGLs revenues varyrevenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our E&P revenuesrevenue and production data for the periods presented:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| Net sales revenues (in thousands, except per unit data) | | | | |
| Oil sales | $ | 107,253 |
| | | $ | 44,201 |
|
| Natural gas sales | 11,959 |
| | | 9,583 |
|
| Natural gas liquids sales | 13,880 |
| | | 7,548 |
|
| Total net sales revenues | $ | 133,092 |
| | | $ | 61,332 |
|
| | | | | |
| Net production: | | | | |
| Oil (Mbbls) | 1,539 |
| | | 938 |
|
| Natural gas (MMcf) | 5,116 |
| | | 3,729 |
|
| NGLs (Mbbls) | 685 |
| | | 322 |
|
| Total (MBoe) | 3,077 |
| | | 1,881 |
|
| | | | | |
| Average net daily production volume: | | | | |
| Oil (Mbbls/d) | 16.7 |
| | | 10.2 |
|
| Natural gas (MMcf/d) | 55.6 |
| | | 40.5 |
|
| NGLs (Mbbls/d) | 7.4 |
| | | 3.5 |
|
| Total (MBoe/d) | 33.4 |
| | | 20.4 |
|
| | | | | |
| Average sales prices: | | | | |
| Oil (per bbl) | $ | 69.67 |
| | | $ | 47.15 |
|
| Effect of derivative settlements on average price (per bbl) | (8.88 | ) | | | 0.99 |
|
| Oil, net of hedging (per bbl) | $ | 60.79 |
| | | $ | 48.14 |
|
| Percentage of unhedged realized oil price to NYMEX | 100 | % | | | 98 | % |
| | | | | |
| Natural gas (per Mcf) | $ | 2.34 |
| | | $ | 2.57 |
|
| Effect of derivative settlements on average price (per Mcf) | (0.04 | ) | | | 0.27 |
|
| Natural gas, net of hedging (per Mcf) | $ | 2.30 |
| | | $ | 2.84 |
|
| Percentage of unhedged realized natural gas. price to NYMEX | 82 | % | | | 87 | % |
| | | | | |
| Natural gas liquids (per bbl) | $ | 20.26 |
| | | $ | 23.44 |
|
| Effect of derivative settlements on average price (per bbl) | — |
| | | (1.24 | ) |
| Natural gas liquids, net of hedging (per bbl) | $ | 20.26 |
| | | $ | 22.20 |
|
| Percentage of unhedged realized oil price to NYMEX | 29 | % | | | 49 | % |
|
| | | | | | | |
| (in thousands, except per unit data) | Second Quarter 2019 | | Second Quarter 2018 |
| Net production: | | | |
| Oil (Mbbls) | 1,545 |
| | 1,123 |
|
| Natural gas (MMcf) | 6,283 |
| | 3,944 |
|
| NGLs (Mbbls) | 819 |
| | 554 |
|
| Total (MBoe) | 3,411 |
| | 2,334 |
|
| | | | |
| Average net daily production volumes: | | | |
| Oil (Mbblsd) | 17.0 |
| | 12.3 |
|
| Natural gas (MMcfd) | 69.0 |
| | 43.3 |
|
| NGLs (Mbblsd) | 9.0 |
| | 6.1 |
|
| Total (MBoed) | 37.5 |
| | 25.6 |
|
| | | | |
| Average sales prices: | | | |
| Oil (per bbl) | $ | 58.67 |
| | $ | 67.09 |
|
| Effect of realized derivatives settlements (per bbl) | 0.12 |
| | (12.80 | ) |
| Oil, after hedging (per bbl) | $ | 58.79 |
| | $ | 54.29 |
|
| Percentage of unhedged realized oil price to NYMEX oil price | 97 | % | | 99 | % |
| | | | |
| Natural gas (per Mcf) | $ | 1.97 |
| | $ | 2.02 |
|
| Effect of realized derivatives settlements (per Mcf) | 0.06 |
| | — |
|
| Natural gas, after hedging (per Mcf) | $ | 2.03 |
| | $ | 2.02 |
|
| | | | |
| NGLs (per bbl) | $ | 12.52 |
| | $ | 18.47 |
|
| Effect of realized derivatives settlements (per bbl) | — |
| | — |
|
| NGLs, after hedging (per bbl) | $ | 12.52 |
| | $ | 18.47 |
|
| | | | |
| Revenue | | | |
| Oil sales | $ | 90,668 |
| | $ | 75,291 |
|
| Natural gas sales | 12,384 |
| | 7,980 |
|
| NGL sales | 10,251 |
| | 10,241 |
|
| Total sales revenue | $ | 113,303 |
| | $ | 93,512 |
|
Oil revenuessales were 81% and 72% of our total net sales revenues for the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), respectively. Oil revenues for the three months ended September 30, 2018 (Successor)Second Quarter 2019 increased approximately $63.1 million, or 143%, as compared to the three months ended September 30, 2017 (Predecessor) due to higher average prices and an increase in production. The higher average prices are tied to the overall increase in oil commodity prices as discussed above. The increase in production for the three months ended September 30, 2018 (Successor) was due to an increase in wells drilled and new wells on production, as compared to the same period in 2017. Oil production was 50% and 50% of total BOE production volume for the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), respectively.
Natural gas revenues were 9% and 16% of our total net sales revenues for the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), respectively. Natural gas revenues for the three months ended September 30, 2018 (Successor) increased approximately $2.4 million, or 25%, as compared to September 30, 2017 (Predecessor) due to an increase in production, partially offset by lower average prices. Natural gassales prices before hedging. The increase in production was 28% and 33% of total BOE production volume for the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), respectively. The lower average prices are tieddue to the overall decrease in natural gas commodity prices as discussed above.extensive development program conducted following the Business Combination.
Natural gas liquids revenuessales were 10% and 12% of our total net sales revenues for the three months ended September 30, 2018 (Successor) andSecond Quarter 2019 increased primarily due to increased production as a result of the extensive development program conducted following the Business Combination.
NGL sales 2017 (Predecessor), respectively. Natural gas liquids revenues for the three months ended September 30, 2018 (Successor)Second Quarter 2019 increased approximately $6.3 million, or 84%, as compared to September 30, 2017 (Predecessor)modestly due to an increase inincreased 2019 production, partiallymostly offset by lower average prices. Natural gas liquids production was 22% and 17% of total BOE production volume for the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), respectively. The increase in production volume was primarily due to (i) increased BOE productionthe impact of oil and natural gas and (ii) an amended contract, commencing inour development activities after the second quarter of 2018, which allows for a greater recovery of ethane.Business Combination.
Gain (loss) on derivative contracts presented
Derivatives
|
| | | | | | | |
| (in thousands) | Second Quarter 2019 | | Second Quarter 2018 |
| Gain (loss) on derivatives: | | | |
| Oil | $ | 191 |
| | $ | (14,362 | ) |
| Natural gas | 353 |
| | 3 |
|
| Total realized gains (losses) | 544 |
| | (14,359 | ) |
| Unrealized gains (losses) | 11,868 |
| | (14,860 | ) |
| Total gain (loss) on derivatives | $ | 12,412 |
| | $ | (29,219 | ) |
Decreases and increases in the table below represents cash settlements related to thefuture commodity as well as fair value changes on our open oil, natural gas and natural gas liquids derivative contracts. The changes in fair value resulted from new positions and settlements that occurredprices during each period as well ascompared to futures prices in effect at the relationship between contract pricestime of execution of our outstanding derivatives resulted in the gains and the associated forward curves.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| Gain (loss) on derivative contracts (in thousands): | | | | |
| Oil | $ | (13,663 | ) | | | $ | 925 |
|
| Natural gas | (204 | ) | | | 994 |
|
| Natural gas liquids | — |
| | | (398 | ) |
| Total cash settlements | (13,867 | ) | | | 1,521 |
|
| Valuation changes | 2,655 |
| | | (11,989 | ) |
| Total gain (loss) on derivative contracts | $ | (11,212 | ) | | | $ | (10,468 | ) |
Operating Expenses
The following table summarizes selected operating expenses for the periods indicated:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| Operating expenses (in thousands, except per BOE data): | | | | |
| Lease operating expense | $ | 16,351 |
| | | $ | 10,407 |
|
| Marketing and transportation expense | 15,820 |
| | | 8,314 |
|
| Production taxes | 6,311 |
| | | 1,262 |
| Workover expense | 1,065 |
| | | 1,441 |
|
| Depreciation, depletion and amortization expense | 45,623 |
| | | 24,159 |
|
| | | | | |
| Production cost per BOE: | | | | |
| Lease operating expense | $ | 5.31 |
| | | $ | 5.53 |
|
| Marketing and transportation expense | 5.14 |
| | | 4.42 |
|
| Production taxes | 2.05 |
| | | 0.67 |
|
| Workover expense | 0.35 |
| | | 0.77 |
|
| Depreciation, depletion and amortization expense | 14.83 |
| | | 12.84 |
|
|
| | | | | | | |
| (in thousands, except per unit data) | Second Quarter 2019 | | Second Quarter 2018 |
| Operating expenses: | | | |
| Lease operating | $ | 19,123 |
| | $ | 12,679 |
|
| Transportation and marketing | 19,614 |
| | 11,206 |
|
| Production taxes | 5,117 |
| | 2,606 |
|
| Workovers | 412 |
| | 333 |
|
| Exploration | 3,289 |
| | 8,083 |
|
| Depreciation, depletion and amortization | 34,504 |
| | 26,670 |
|
| Impairment of assets | 6,500 |
| | — |
|
| General and administrative | 15,723 |
| | 17,811 |
|
| Total operating expense | $ | 104,282 |
| | $ | 79,388 |
|
| | | | |
| Operating expenses per BOE: | | | |
| Lease operating | $ | 5.61 |
| | $ | 5.43 |
|
| Transportation and marketing | 5.75 |
| | 4.80 |
|
| Production taxes | 1.50 |
| | 1.12 |
|
| Workovers | 0.12 |
| | 0.14 |
|
| Depreciation, depletion and amortization | 10.12 |
| | 11.43 |
|
Lease operating expense primarily consists of costs related to compression, chemicals, fuel, power and water and associated labor. Lease operating expense for the three months ended September 30, 2018 (Successor) Second Quarter 2019increased approximately $5.9 million, or 57%, as compared to the three months ended September 30, 2017 (Predecessor), primarily due to increasedhigher production and the impact of additional costs associated with saltthe sale of our produced water disposal and additional wells drilled. The decrease in cost per BOE was primarily dueassets to increased NGL production resulting from higher plant recovery rates and from an amended contract which allows for a greater recovery of ethane, commencingour affiliate KFM in the secondfourth quarter of 2018. See
Transportation and marketing expense Note 17 — Related Party Transactions for further detail.
Marketing and transportation expense represents throughput for our properties in the STACK primarily at the Kingfisher processing facility. Marketing and transportation expense for the three months ended September 30, 2018 (Successor) Second Quarter 2019increased approximately $7.5 million or 90%, as compared to September 30, 2017 (Predecessor), primarily due to higher volumes flowing from our operated wells into the Kingfisher plant.volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The amount for the Second Quarter 2019 also reflects a more significant expense due to an increase in committed capacity which went unused.
Production taxes for the three months ended September 30, 2018 (Successor) Second Quarter 2019increased approximately $5.0 million, or 400%, as compared due to the three months ended September 30, 2017 (Predecessor), primarily due to an increase in oil and natural gas liquidsNGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018. 2018, for wells in their first 3 years of production.
|
| | | | | | | |
| (in thousands) | Second Quarter 2019 | | Second Quarter 2018 |
| Exploration expense: | | | |
| Geological and geophysical costs | $ | 366 |
| | $ | 1,139 |
|
| Other exploration expense, including expired leases | 2,909 |
| | 6,579 |
|
| ARO settlements in excess of recorded liabilities | 14 |
| | 365 |
|
| Total exploration expense | $ | 3,289 |
| | $ | 8,083 |
|
Workover expensesExploration expense associated with maintenance and remedial efforts to increase production decreased approximately $0.4 million during the three months ended September 30, 2018 (Successor), asSecond Quarter 2019decreased compared to the three months ended September 30, 2017 (Predecessor), primarilySecond Quarter 2018 largely due to the timing and extent$3.7 million of related projects during each period.lower expired lease costs.
Depreciation, depletion and amortization expensewas higherlower on a per BOE basis forduring the three months ended September 30, 2018 (Successor) as comparedSecond Quarter 2019 largely due to the three months ended September 30, 2017 (Predecessor), primarily due to an increase in capital spendingamount of impairment taken on our oil and in production in relation to current reserves.gas properties during the fourth quarter of 2018, which reduced the depletable base.
During the Second Quarter 2019, we recognized a $6.5 million impairment of our operating lease right-of-use assets.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| Exploration expense (in thousands): | | | | |
| Geological and geophysical costs | $ | 947 |
| | | $ | 1,203 |
|
| Exploration expense | 149 |
| | | 2,445 |
|
| Loss on ARO settlement | (67 | ) | | | 1 |
|
| Total exploration expense | $ | 1,029 |
| | | $ | 3,649 |
|
Exploration expense consists primarily of geological and geophysical personnel and data costs, lease rental expenses, expired leases, dry hole costs and settlements of asset retirement obligations (“ARO”) in excess of recorded estimates. Total exploration expense decreased $2.6 million, primarily due to a decrease in expired leaseholds of $2.3 million that were recognized in the Predecessor period.
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| General and administrative expenses (in thousands): | | | | |
| Equity-based compensation expense | $ | 325 |
| | | $ | — |
|
| General and administrative expenses | 7,593 |
| | | 17,445 |
|
| Total general and administrative expenses | $ | 7,918 |
| | | $ | 17,445 |
|
|
| | | | | | | |
| (in thousands) | Second Quarter 2019 | | Second Quarter 2018 |
| General and administrative expense: | | | |
| Employee-related costs | $ | 6,649 |
| | $ | 6,126 |
|
| Equity-based compensation | 1,396 |
| | 3,621 |
|
| Professional fees | 126 |
| | 3,843 |
|
| Strategic costs | 4,061 |
| | — |
|
| Business Combination | — |
| | 443 |
|
| Severance costs | 609 |
| | — |
|
| Information technology | 946 |
| | 2,146 |
|
| Operating leases | 1,293 |
| | 995 |
|
| Provision for uncollectible receivables | 298 |
| | — |
|
| Other | 345 |
| | 637 |
|
| Total general and administrative expense | $ | 15,723 |
| | $ | 17,811 |
|
General and administrative expense(expenses “G&A”). Forduring the three months ended September 30, 2018 (Successor), G&ASecond Quarter 2019 decreased approximately $9.5 million, or 55%, as compareddue mainly to the three months ended September 30, 2017 (Predecessor), primarily due to (i) lower legal costs associated with a 2017 legal settlement of $4.7 million, (ii) lowerequity-based compensation expense and information technology costs related to non-recurring consulting fees attributable toassociated with the Contribution Agreement with SRII Opco of approximately $2.5 million incurred during the third quarter of 2017change in control. General and (iii) a reduction in employee incentive compensationadministrative expense during the three months ended September 30, 2018 as compared to the Predecessor Period.Second Quarter 2019 also included costs for legal and financial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and other third parties.
Other Income (Expense)Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:
|
| | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2018 | | | Three Months Ended September 30, 2017 |
| Interest expense (in thousands): | | | | |
| Senior secured revolving credit facility | $ | 528 |
| | | $ | 3,139 |
|
| Senior unsecured notes | 8,613 |
| | | 10,187 |
|
| Other | 1,867 |
| | | 219 |
|
| Total interest expense | $ | 11,008 |
| | | $ | 13,545 |
|
|
| | | | | | | |
| (in thousands) | Second Quarter 2019 | | Second Quarter 2018 |
| Income (loss) from continuing operations before income taxes | $ | 7,746 |
| | $ | (22,470 | ) |
| | | | |
| Interest expense | 14,071 |
| | 10,361 |
|
| Depreciation, depletion and amortization | 34,504 |
| | 26,670 |
|
| Exploration | 3,289 |
| | 8,083 |
|
| Loss (gain) on unrealized hedges | (11,868 | ) | | 14,860 |
|
| Impairment of assets | 6,500 |
| | — |
|
| Equity-based compensation | 1,396 |
| | 3,621 |
|
| Severance costs | 609 |
| | — |
|
| Strategic costs | 4,061 |
| | — |
|
| Business Combination | — |
| | 443 |
|
| Adjusted EBITDAX | $ | 60,308 |
| | $ | 41,568 |
|
Other (Income) Expense
|
| | | | | | | |
| (in thousands) | Second Quarter 2019 | | Second Quarter 2018 |
| Alta Mesa RBL | $ | 5,204 |
| | $ | — |
|
| 2024 Notes | 9,844 |
| | 9,844 |
|
| Bond premium amortization | (1,231 | ) | | (1,231 | ) |
| Deferred financing cost amortization | 94 |
| | 80 |
|
| Other | 160 |
| | 1,668 |
|
| Total interest expense | 14,071 |
| | 10,361 |
|
| Interest income and other | (54 | ) | | (820 | ) |
| Total other expense, net | $ | 14,017 |
| | $ | 9,541 |
|
Interest expense.expense Forfor the three months ended September 30, 2018 (Successor),Second Quarter 2019 increased due primarily to increased levels of borrowings under the Alta Mesa RBL. Other interest expense decreased $2.5 million, or 19%, as compared to the three months ended September 30, 2017 (Predecessor), primarily due to (i) lower interest on the Eighth A&R credit facility of $2.6 million, resulting from the repayment of our predecessor senior secured revolving credit facility in connection with the Business Combination,includes commitment fees and (ii) bond premium amortization of $1.2 million. These decreases were partially offset by the increase in other interest expense of $1.2 million related to our joint development agreement with BCE.
For the Six Months Ended June 30, 2019 (“2019 Period”) Compared to the Periods from February 9, 2018 Through SeptemberJune 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to the Nine Months Ended September 30, 2017 (Predecessor)
The tables included below set forth financial information for the Successor Period, the 2018 Predecessor PeriodPeriods and the 2017 Predecessor Period, which are distinct reporting periods as a result of the Business Combination.periods. The Predecessor Period amounts below exclude operating results related to discontinued operations. For simplicity, in our discussion below, we refer to the combined periods February 9, 2018 through June 30, 2018 and January 1, 2018 through February 8, 2018 as the “2018 period”.
Revenues
Our oil, natural gas and NGLs revenues varyrevenue varies as a result of changes in commodity prices and production volumes. The following table summarizes our revenuesrevenue and production data for the periods presented:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Net sales revenues (in thousands, except per unit data) | | | | | | |
| Oil sales | $ | 222,822 |
| | | $ | 30,972 |
| | $ | 133,489 |
|
| Natural gas sales | 25,149 |
| | | 4,276 |
| | 29,816 |
|
| Natural gas liquids sales | 28,835 |
| | | 4,000 |
| | 21,201 |
|
| Total net sales revenues | $ | 276,806 |
|
| | $ | 39,248 |
|
| $ | 184,506 |
|
| | | | | | | |
| Net production: | | | | | | |
| Oil (Mbbls) | 3,313 |
| | | 494 |
| | 2,783 |
|
| Natural gas (MMcf) | 11,308 |
| | | 1,609 |
| | 10,732 |
|
| NGLs (Mbbls) | 1,462 |
| | | 151 |
| | 911 |
|
| Total (MBoe) | 6,660 |
| | | 914 |
| | 5,483 |
|
| | | | | | | |
| Average net daily production volume: | | | | | | |
| Oil (Mbbls/d) | 14.2 |
| | | 12.7 |
| | 10.2 |
|
| Natural gas (MMcf/d) | 48.3 |
| | | 41.2 |
| | 39.3 |
|
| NGLs (Mbbls/d) | 6.2 |
| | | 3.9 |
| | 3.3 |
|
| Total (MBoe/d) | 28.5 |
| | | 23.4 |
| | 20.1 |
|
| | | | | | | |
| Average sales prices: | | | | | | |
| Oil (per bbl) | $ | 67.26 |
| | | $ | 62.68 |
| | $ | 47.97 |
|
| Effect of derivative settlements on average price (per bbl) | (10.02 | ) | | | (6.44 | ) | | 0.30 |
|
| Oil, net of hedging (per bbl) | $ | 57.24 |
|
| | $ | 56.24 |
|
| $ | 48.27 |
|
| Percentage of unhedged realized oil price to NYMEX | 100 | % | | | 99 | % | | 97 | % |
| | | | | | | |
| Natural gas (per Mcf) | $ | 2.22 |
| | | $ | 2.66 |
| | $ | 2.78 |
|
| Effect of derivative settlements on average price (per Mcf) | 0.03 |
| | | 0.94 |
| | 0.16 |
|
| Natural gas, net of hedging (per Mcf) | $ | 2.25 |
|
| | $ | 3.60 |
|
| $ | 2.94 |
|
| Percentage of unhedged realized natural gas price to NYMEX | 79 | % | | | 87 | % | | 91 | % |
| | | | | | | |
| Natural gas liquids (per bbl) | $ | 19.72 |
| | | $ | 26.41 |
| | $ | 23.27 |
|
| Effect of derivative settlements on average price (per bbl) | — |
| | | — |
| | (0.87 | ) |
| Natural gas liquids, net of hedging (per bbl) | $ | 19.72 |
|
| | $ | 26.41 |
|
| $ | 22.40 |
|
| Percentage of unhedged realized oil price to NYMEX | 29 | % | | | 42 | % | | 47 | % |
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands, except per unit data) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018 Through February 8, 2018 |
| Net production: | | | | | | |
| Oil (Mbbls) | 3,164 |
| | 1,774 |
| | | 494 |
|
| Natural gas (MMcf) | 12,114 |
| | 6,192 |
| | | 1,609 |
|
| NGLs (Mbbls) | 1,614 |
| | 777 |
| | | 151 |
|
| Total (MBoe) | 6,797 |
| | 3,583 |
| | | 914 |
|
| | | | | | | |
| Average net daily production volumes: | | | | | | |
| Oil (Mbblsd) | 17.5 |
| | 12.5 |
| | | 12.7 |
|
| Natural gas (MMcfd) | 66.9 |
| | 43.6 |
| | | 41.2 |
|
| NGLs (Mbblsd) | 8.9 |
| | 5.5 |
| | | 3.9 |
|
| Total (MBoed) | 37.6 |
| | 25.2 |
| | | 23.4 |
|
| | | | | | | |
| Average sales prices: | | | | | | |
| Oil (per bbl) | $ | 55.94 |
| | $ | 65.16 |
| | | $ | 62.68 |
|
| Effect of realized derivatives settlements (per bbl) | 0.61 |
| | (11.01 | ) | | | (6.44 | ) |
| Oil, after hedging (per bbl) | $ | 56.55 |
| | $ | 54.15 |
| | | $ | 56.24 |
|
| Percentage of unhedged realized oil price to NYMEX oil price | 97 | % | | 99 | % | | | 99 | % |
| | | | | | | |
| Natural gas (per Mcf) | $ | 2.55 |
| | $ | 2.13 |
| | | $ | 2.66 |
|
| Effect of realized derivatives settlements (per Mcf) | (0.08 | ) | | 0.09 |
| | | 0.94 |
|
| Natural gas, after hedging (per Mcf) | $ | 2.47 |
| | $ | 2.22 |
| | | $ | 3.60 |
|
| | | | | | | |
| NGLs (per bbl) | $ | 13.30 |
| | $ | 19.25 |
| | | $ | 26.41 |
|
| Effect of realized derivatives settlements (per bbl) | — |
| | — |
| | | — |
|
| NGLs, after hedging (per bbl) | $ | 13.30 |
| | $ | 19.25 |
| | | $ | 26.41 |
|
| | | | | | | |
| Revenue | | | | | | |
| Oil sales | $ | 177,031 |
| | $ | 115,569 |
| | | $ | 30,972 |
|
| Natural gas sales | 30,834 |
| | 13,190 |
| | | 4,276 |
|
| NGL sales | 21,467 |
| | 14,955 |
| | | 4,000 |
|
| Total sales revenue | $ | 229,332 |
| | $ | 143,714 |
| | | $ | 39,248 |
|
Oil revenues were 81%, 79% and 72% of our total net sales revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Oil revenues for the Successor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period due to higher average prices and an increase in production in 2018. The higher average prices are tied to the overall increase in oil commodity prices as discussed above. The increase in production in 2018 was due to an increase in wells drilled and new wells on production. Oil production was approximately 50%, 54% and 50% of total BOE production volume in the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.
Natural gas revenuesOil sales were 9%, 11% and 16% of our total net sales revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas revenues for the Successor Period and the 2018 Predecessor Period decreased slightly compared to the 2017 Predecessor Period2019 period increased due to lower average prices,increased production, partially offset by anlower average sales prices before hedging. The increase in production in 2018. The lower average prices are tiedwas due to the overall decrease in natural gas commodity prices as discussed above. Natural gas production was approximately 28%, 29% and 33% of total BOE production volume forextensive development program conducted following the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.Business Combination.
Natural gas liquid revenuessales were 10%, 10% and 12% of our total net sales revenues for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Natural gas liquid revenues for the Successor Period and the 2018 Predecessor Period2019 period increased compareddue to the 2017 Predecessor Period due toboth an increase in production duringas a result of the extensive development program conducted following the Business Combination and higher prevailing market prices.
NGL sales for the 2019 period partiallyincreased due to increased production, significantly offset by lower average prices. Natural gas liquids production was approximately 22%, 17% and 17% of total BOE production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The increase in production volume was primarily due to (i) increased BOE productionthe impact of oil and natural gas and (ii) an amended contract, commencing inour extensive 2018 development activities following the second quarter of 2018, which allows for a greater recovery of ethane. Business Combination.
Gain (loss) on sale of assets and other primarily includesfor the 2019 period included a gain forfrom the sale of seismic data totaling $1.5 million compared to a similar gain of $5.9 million induring the Successor Period.2018 period.
Gain (loss) on derivative contracts presentedDerivatives
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Gain (loss) on derivatives: | | | | | | |
| Oil | $ | 1,936 |
| | $ | (18,892 | ) | | | $ | (3,819 | ) |
| Natural gas | (1,027 | ) | | 558 |
| | | 1,523 |
|
| Total realized gains (losses) | 909 |
| | (18,334 | ) | | | (2,296 | ) |
| Unrealized gains (losses) | (12,274 | ) | | (32,896 | ) | | | 8,959 |
|
| Total gain (loss) on derivatives | $ | (11,365 | ) | | $ | (51,230 | ) | | | $ | 6,663 |
|
Decreases and increases in the table below represents cash settlements related to thefuture commodity as well as fair value changes in our oil, natural gas and natural gas liquids derivative contracts. The changes in fair value resulted from new positions and settlements that occurredprices during each period as well ascompared to futures prices in effect at the relationship between contract pricestime of execution of our outstanding derivatives resulted in the gains and the associated forward curves.losses recognized, respectively, during each six month period.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Gain (loss) on derivative contracts (in thousands): | | | | | | |
| Oil | $ | (33,190 | ) | | | $ | (3,184 | ) | | $ | 846 |
|
| Natural gas | 354 |
| | | 1,523 |
| | 1,719 |
|
| Natural gas liquids | — |
| | | — |
| | (790 | ) |
| Total cash settlements | (32,836 | ) |
| | (1,661 | ) |
| 1,775 |
|
| Valuation changes | (30,241 | ) | | | 8,959 |
| | 36,249 |
|
| Total gain (loss) on derivative contracts | $ | (63,077 | ) |
| | $ | 7,298 |
|
| $ | 38,024 |
|
Operating Expenses
The following table summarizes selected operating expenses for the periods indicated:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Operating expenses (in thousands, except per BOE data): | | | | | | |
| Lease operating expense | $ | 37,347 |
| | | $ | 4,485 |
| | $ | 32,897 |
|
| Marketing and transportation expense | 32,608 |
| | | 3,725 |
| | 20,486 |
|
| Production taxes | 10,332 |
| | | 953 |
| | 3,712 |
|
| Workover expense | 2,643 |
| | | 423 |
| | 3,131 |
|
| Depreciation, depletion and amortization expense | 83,068 |
| | | 11,784 |
| | 63,247 |
|
| | | | | | | |
| Production cost per BOE: | | | | | | |
| Lease operating expense | $ | 5.61 |
| | | $ | 4.91 |
| | $ | 6.00 |
|
| Marketing and transportation expense | 4.90 |
| | | 4.08 |
| | 3.74 |
|
| Production taxes | 1.55 |
| | | 1.04 |
| | 0.68 |
|
| Workover expense | 0.40 |
| | | 0.46 |
| | 0.57 |
|
| Depreciation, depletion and amortization expense | 12.47 |
| | | 12.89 |
| | 11.54 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands, except per unit data) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Operating expenses: | | | | | | |
| Lease operating | $ | 44,231 |
| | $ | 20,996 |
| | | $ | 4,408 |
|
| Transportation and marketing | 37,375 |
| | 16,788 |
| | | 3,725 |
|
| Production taxes | 10,600 |
| | 4,021 |
| | | 953 |
|
| Workovers | 609 |
| | 1,578 |
| | | 423 |
|
| Exploration | 5,343 |
| | 9,668 |
| | | 7,003 |
|
| Depreciation, depletion and amortization | 69,179 |
| | 37,708 |
| | | 11,670 |
|
| Impairment of assets | 6,500 |
| | — |
| | | — |
|
| General and administrative | 36,670 |
| | 52,465 |
| | | 21,234 |
|
| Total operating expense | $ | 210,507 |
| | $ | 143,224 |
| | | $ | 49,416 |
|
| | | | | | | |
| Operating expenses per BOE: | | | | | | |
| Lease operating | $ | 6.51 |
| | $ | 5.86 |
| | | $ | 4.82 |
|
| Transportation and marketing | 5.50 |
| | 4.69 |
| | | 4.08 |
|
| Production taxes | 1.56 |
| | 1.12 |
| | | 1.04 |
|
| Workovers | 0.09 |
| | 0.44 |
| | | 0.46 |
|
| Depreciation, depletion and amortization | 10.18 |
| | 10.52 |
| | | 12.77 |
|
Lease operating expense primarily consists of costs related to compression, chemicals, fuel, power and water and associated labor. Lease operating expense for the Successor Period and the 2018 Predecessor Period2019 period increased compared to the 2017 Predecessor Period due to increased costs associated with salt water disposal and additional wells drilled. The lease operating expense cost per BOE for the Successor Period and 2018 Predecessor Period was lower as compared to the 2017 Predecessor Period primarily due to increased NGL production resulting from higher BOE production of oil and natural gas and from an amended contract which allows for a greater recovery of ethane, commencing in the second quarter of 2018. See Note 17 — Related Party Transactions for further detail.
Marketing and transportation expense represents throughput for our properties in the STACK primarily at the Kingfisher processing facility. The increase is primarily due to higher volumes flowing fromproduction and the impact of additional costs associated with the sale of our operated wells intoproduced water assets to our affiliate KFM in the Kingfisher plant.fourth quarter of 2018.
Transportation and marketing expense for the 2019 period increased primarily due to higher volumes. The fee we pay per unit reflects the firm processing capacity at the plant, as well as firm transport for our residue gas at the tailgate of the plant. The 2019 period also reflects a more significant expense due to an increase in committed capacity which went unused.
Production taxes for the Successor Period and 2018 Predecessor Period are higher as compared to the 2017 Predecessor Period2019 period increased primarily due to the increase in oil and natural gas liquidsNGL revenue and an increase in the Oklahoma severance tax rate from 2% to 5%, effective in the third quarter of 2018.2018, for wells in their first 3 years of production.
Workover expensesWorkovers are associated with maintenance and remedialother efforts to increase productionproduction. During the 2019 period, these costs decreased slightly for the Successor Period and 2018 Predecessor Period, as compared to the 2017 Predecessor Period primarily due to the timing and extent of relatedminimal workover projects during each period.being undertaken.
Depreciation, depletion and amortization expense was higher on a per BOE basis for the Successor Period as compared to the 2018 Predecessor Period and the 2017 Predecessor Period, primarily due to an increase in capital spending and in production in relation to current reserves. |
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Exploration expense: | | | | | | |
| Geological and geophysical costs | $ | 678 |
| | $ | 1,590 |
| | | $ | 2,440 |
|
| Other exploration expense, including expired leases | 4,604 |
| | 7,412 |
| | | 4,504 |
|
| ARO settlements in excess of recorded liabilities | 61 |
| | 666 |
| | | 59 |
|
| Total exploration expense | $ | 5,343 |
| | $ | 9,668 |
| | | $ | 7,003 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Exploration expense (in thousands): | | | | | | |
| Geological and geophysical costs | $ | 2,537 |
| | | $ | 2,440 |
| | $ | 4,783 |
|
| Exploratory dry hole costs | — |
| | | (45 | ) | | — |
|
| Exploration expense | 10,931 |
| | | 1,179 |
| | 7,068 |
|
| Loss on ARO settlements | 599 |
| | | 59 |
| | 37 |
|
| Total exploration expense | $ | 14,067 |
|
| | $ | 3,633 |
|
| $ | 11,888 |
|
Exploration expense consists primarily of geological and geophysical personnel and data costs, lease rental expenses, expired leases, dry hole costs and settlements of asset retirement obligations in excess of recorded estimates. Total exploration expense for the Successor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period,2019 period decreased primarily due to an increaseour cost reduction efforts, including a reduced number of employees in the geology department, and a decrease in expenses relating to expired leaseholds of $5.2 million.or expiring leaseholds.
During the 2019 period, we recognized a $6.5 million impairment of our operating lease right-of-use assets.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| General and administrative expense (in thousands): | | | | | | |
| Equity-based compensation expense | $ | 6,714 |
| | | $ | — |
| | $ | — |
|
| General and administrative expenses | 50,474 |
| | | 24,352 |
| | 35,474 |
|
| Total general and administrative expenses | $ | 57,188 |
|
| | $ | 24,352 |
|
| $ | 35,474 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| General and administrative expense: | | | | | | |
| Employee-related costs | $ | 14,957 |
| | $ | 12,646 |
| | | $ | 1,032 |
|
| Equity-based compensation | 3,057 |
| | 6,389 |
| | | — |
|
| Professional fees | 3,723 |
| | 5,083 |
| | | 1,019 |
|
| Strategic costs | 4,061 |
| | — |
| | | — |
|
| Business Combination | 10 |
| | 23,717 |
| | | 17,040 |
|
| Severance costs | 4,584 |
| | — |
| | | — |
|
| Information technology | 1,980 |
| | 2,649 |
| | | — |
|
| Operating leases | 2,317 |
| | 1,486 |
| | | 208 |
|
| Provision for uncollectible receivables | 1,177 |
| | — |
| | | — |
|
| Other | 804 |
| | 495 |
| | | 1,935 |
|
| Total general and administrative expense | $ | 36,670 |
| | $ | 52,465 |
| | | $ | 21,234 |
|
General and administrative expense includes non-cash charges for equity-based compensation awardsthe 2019 period decreased compared to the 2018 period primarily due to nonrecurring Business Combination costs and other professional fees incurred in the Successor Period. See Note 16 — Equity-Based Compensation (Successor)2018 period for further detail on equity-based compensation awards grantedadvisors helping to value and integrate the acquired business. General and administrative expense during the Successor Period. No such awards were made during the Predecessor Periods. G&A expenses2019 period also included costs for the Successor Periodlegal and the 2018 Predecessor Period included $25.7 millionfinancial advisory services associated with financial structuring activities, including negotiations with representatives of our lenders and $17.0 million, respectively, of transaction expenses primarily attributable to the consummation of the Business Combination.other third parties.
Below is a reconciliation of our income (loss) from continuing operations before income taxes to our Adjusted EBITDAX:
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | February 9, 2018 Through September 30, 2018 | | | January 1, 2018 Through February 8, 2018 | | Nine Months Ended
September 30, 2017 |
| Interest expense (in thousands): | | | | | | |
| Senior secured revolving credit facility | $ | 608 |
| | | $ | 867 |
| | $ | 6,880 |
|
| Senior unsecured notes | 22,148 |
| | | 3,399 |
| | 30,534 |
|
| Other | 3,809 |
| | | 1,245 |
| | 751 |
|
| Total interest expense | $ | 26,565 |
|
| | $ | 5,511 |
|
| $ | 38,165 |
|
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Income (loss) from continuing operations before income taxes | $ | (16,979 | ) | | $ | (57,071 | ) | | | $ | (7,116 | ) |
| | | | | | | |
| Interest expense | 26,901 |
| | 15,557 |
| | | 5,511 |
|
| Depreciation, depletion and amortization | 69,179 |
| | 37,708 |
| | | 11,670 |
|
| Exploration | 5,343 |
| | 9,668 |
| | | 7,003 |
|
| Loss (gain) on unrealized hedges | 12,274 |
| | 32,896 |
| | | (8,959 | ) |
| Loss on sale of property and equipment | — |
| | 63 |
| | | — |
|
| Impairment of assets | 6,500 |
| | — |
| | | — |
|
| Equity-based compensation | 3,057 |
| | 6,389 |
| | | — |
|
| Severance costs | 4,584 |
| | — |
| | | — |
|
| Strategic costs | 4,061 |
| | — |
| | | — |
|
| Business Combination | 10 |
| | 23,717 |
| | | 17,040 |
|
| Adjusted EBITDAX | $ | 114,930 |
| | $ | 68,927 |
| | | $ | 25,149 |
|
Interest expense. Other (Income) Expense
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Alta Mesa RBL | $ | 8,783 |
| | $ | 252 |
| | | $ | 815 |
|
| 2024 Notes | 19,688 |
| | 16,406 |
| | | 3,281 |
|
| Bond premium amortization | (2,462 | ) | | (2,051 | ) | | | — |
|
| Deferred financing cost amortization | 139 |
| | 80 |
| | | 171 |
|
| Other | 753 |
| | 870 |
| | | 1,244 |
|
| Total interest expense | 26,901 |
| | 15,557 |
| | | 5,511 |
|
| Interest income and other | (81 | ) | | (1,366 | ) | | | (172 | ) |
| Total other expense, net | $ | 26,820 |
| | $ | 14,191 |
| | | $ | 5,339 |
|
Interest expense infor the Successor Period2019 period increased primarily due to increased levels of borrowing under the Alta Mesa RBL. Other interest expense includes amortization of our deferred financing cost related to the Eighth A&R credit facility, interest on our senior unsecured notes, net of bond premium amortization of $3.3 million, and other interest, such as commitment fees and interest expense related to our joint development agreement with BCE. The amounts outstanding under the previous revolving credit facility during the Predecessor Periods were repaid in full at the time of the Business Combination.
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 interest onrelated to servicing our debt and any amounts owed during the period related to
hedges. During 2019, our hedging positions. Our main sources of liquidity and capital resources have come from operating cash flows generated from operations,flow and borrowings under the Eighth A&RAlta Mesa RBL, including a $66.5 million draw in April 2019.
During April 2019, our borrowing base was reduced from $400.0 million to $370.0 million as part of the semi-annual redetermination. At June 30, 2019, we had outstanding borrowings of approximately $344.5 million and outstanding letters of credit facilityof $20.2 million, leaving us $5.3 million of remaining borrowing capacity. We held $78.3 million of cash and cash equivalents on hand at June 30, 2019. We do not anticipate maintaining compliance with the consolidated total leverage ratio
covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019. Also, in August 2019 the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reduced to $200 million. As such, we are required to repay the $162.4 million of combined excess of our borrowings and letters of credit outstanding ratably over five months in $32.5 million installments, which will have an adverse impact on our liquidity. The first payment is due in September 2019. If we are unable to make repayment of this amount, we will be in default under the Alta Mesa RBL. As a consequence of both reduced operating cash flow and a reduced borrowing base, we may have limited ability to obtain the capital contributionsnecessary to conduct our operations at desired levels. Our general partner’s board of directors and our parent’s board of directors and its financial advisors are evaluating the available financial alternatives, waivers to the covenants or other provisions of our indebtedness, raising new capital from the private or public markets or taking other actions to address our parent AMR.capital structure. If we are unable to reach an agreement with our lenders or find acceptable alternative financing, it may lead to an event of default under the Alta Mesa RBL. If an event of default occurs and the Alta Mesa RBL lenders were to accelerate repayment, it may result in an acceleration of the 2024 Notes. We have concluded that these and other circumstances create substantial doubt regarding our ability to continue as a going concern. We currently anticipate that our indebtedness will accelerate prior to July 1, 2020 and therefore, have reported all of our debt as current at June 30 2019.
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 constraintsmidstream availability, other working interest owner participation and regulatory approvals. Amatters. Any deferral of planned capital expenditures, particularly with respect to drilling and completingbringing new wells onto production, could reduce our anticipated production, revenue and cash flow, and may result in a reduction in anticipated production, revenues and cash flows. Additionally, if we curtail our drilling program, we may lose a portionthe expiry of our acreage through lease expirations.certain leases. However, sincebecause a large percentage of our acreage is held forby production, we have the ability to materially increase or decreasecan alter our drilling and recompletion budget in responseprogram to market conditions with decreasedminimize the 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 considered 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.
WeAlthough we are currently capitally constrained, we strive to maintain financial flexibility and, if available on terms we find acceptable, we may access the debt or equity capital markets as necessary to facilitate drilling on our large undeveloped acreage position and permit usdevelopment program, to selectively expand our acreage position. In the eventposition or to redesign our capital structure. If our operating cash flows areflow is materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may decide to curtail our capital spending.spending which would have an adverse impact on our ability to develop our acreage as we would have otherwise planned.
We expectWith our $370.0 million borrowing base, we expected to fund our capital budget foroperate 2 rigs during the remainder of 2018 predominantly with cash flows from operations, borrowings under2019 to develop our assets, particularly to focus on testing the Eighth A&R credit facilityspacing patterns we believe to be optimal, and to continue executing our cost reduction strategies begun earlier in 2019. Prior to the August 2019 redetermination, we anticipated drilling and completionbringing online approximately 60 to 65 wells during 2019 while incurring approximately $140.0 million to $155.0 million of capital funded throughexpenditures under a 2-rig program. We also expected that an additional $20.0 million to $30.0 million could be incurred for other non-operated projects, leasehold costs and capitalized workover activity. Following the redetermined borrowing base of $200 million in August 2019, we decided to operate 1 rig starting in September. We will continue to evaluate how much, if any, development is appropriate going forward. We do not expect our joint development agreement with BCE. 2019 operating cash flow alone to provide sufficient proceeds to meet our 2019 capital expenditure levels and we would be required to utilize existing cash on hand.
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 the Eighth A&R credit facility willcannot provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and to pursue our currently planned and future development activities. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure youassurance that operations and other needed capital will be available on acceptable terms, or at all. all, and our development pace may need to change based on our evolving liquidity profile.
Senior Unsecured Notes
We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”), which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. during the fourth quarter of 2016. The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017.33
The senior notes will mature on December 15, 2024, and interest is payable semi-annually on June 15 and December 15 of each year. As described further in Note 11 of the Notes to Condensed Consolidated Financial Statements, we may, from time to time, redeem certain amounts of the outstanding senior notes at specified amounts in relation to the principal balance of the notes redeemed.
As of September 30, 2018, we were in compliance with the indentures governing the senior notes.
Senior Secured Revolving Credit Facility
In connection with the consummation of the Business Combination, all indebtedness at that time under the senior secured revolving credit facility was repaid in full. On February 9, 2018, we entered into the Eighth A&R credit facility with Wells Fargo Bank, National Association, as the administrative agent. The Eighth A&R credit facility, which will mature on February 9, 2023, is for an aggregate of $1.0 billion with a current borrowing base of $400.0 million. The Eighth A&R credit facility does not permit us to borrow funds if at the time of such borrowing we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of September 30, 2018, we have $80.0 million of borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $298.1 million available for future use.
On November 13, 2018, the remaining amount available under the Eighth A&R credit facility totaled $270.1 million reflecting borrowings for capital spending and working capital needs, net of proceeds received from the sale of the produced water assets from the Company to a subsidiary of Kingfisher Midstream, LLC as described further in Note 19 of the Notes to Condensed Consolidated Financial Statements.
Cash Flow Analysis
As of September 30, 2018, we were in compliance with the financial ratios specified in the Eight A&R credit facility. |
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash from operating activities | $ | 61,818 |
| | $ | (45,489 | ) | | | $ | 26,336 |
|
| Cash from investing activities | (180,138 | ) | | (307,743 | ) | | | (37,913 | ) |
| Cash from financing activities | 183,500 |
| | 417,913 |
| | | 16,932 |
|
| Net increase in cash, cash equivalents and restricted cash | $ | 65,180 |
| | $ | 64,681 |
| | | $ | 5,355 |
|
Cash flow provided byfrom operating activities
Cash provided by operating activities was $15.5 million, $26.5 million and $56.3 million forDuring the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Cash-based2019 period, cash-based items of net income (loss), including revenuesrevenue (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense were approximately $88.2totaled $73.9 million $(2.4)compared to $29.2 million and $65.8 million for the Successor Period, 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Changes in working capital and other assets and liabilities resulted in a decrease in cash of $72.8 million and $9.5 million for the Successor Period and the 2017 Predecessor Period, respectively. Changes in working capital and other assets and liabilities during the 2018 Predecessor Period resultedperiod, due largely to higher revenues associated with increased production and the lack of costs associated with the Business Combination that were incurred in an2018. Approximately $12.0 million of cash was used to increase working capital during the six months ended June 30, 2019. During the 2018 period, cash totaling $48.4 million was used to increase working capital primarily due to increases in cashtrade receivables and amounts due from related parties for administrative services provided, including certain other transactions, and to reduce liabilities arising prior to or as a result of approximately $28.9 million.the Business Combination.
Cash flow used infrom investing activities
Investing activities used cash for |
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash provided by (used for) | | | | | | |
| Capital expenditures | $ | (180,138 | ) | | $ | (319,042 | ) | | | $ | (36,695 | ) |
| Acquisition of acreage | — |
| | — |
| | | (1,218 | ) |
| Proceeds from sale of property and equipment | — |
| | 11,299 |
| | | — |
|
| Cash from investing activities | $ | (180,138 | ) | | $ | (307,743 | ) | | | $ | (37,913 | ) |
During the 2019 period, capital expenditures included $91.6 million for additions to property and equipment that occurred prior to December 31, 2018. Capital spending during 2019 has decreased significantly from 2018 as a result of approximately $489.0 million, $38.1 millionthe reassessment of our current drilling plans due to the results obtained from our 2018 drilling program and $244.3 million for the Successor Period,our existing liquidity concerns. We ran as many as 9 rigs during the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. During the 2017 Predecessor Period, cash used for acquisitions totaled $55.2 million. Additionally, during the 2017 Predecessor Period, we entered into an interest bearing promissory note receivable with our affiliate Northwest Gas Processing, LLC for approximately $1.5 million.period.
Cash flow provided byfrom financing activities
Cash provided by financing activities was $472.9 million, $16.9 million and $242.1 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. The Successor Period included capital contributions totaling $560.3 million and proceeds from the issuance of long-term debt totaling $80.0 million, offset by repayments on the Alta Mesa senior secured revolving facility totaling $134.1 million, capital distribution of $32.0 million and incurred deferred financing costs of $1.4 million. The 2018 Predecessor Period included proceeds from the issuance of long-term debt totaling $60.0 million, offset by repayments of long-term debt totaling $43.0 million. The 2017 Predecessor Period included proceeds from the issuance of long-term debt totaling $286.1 million and capital contributions totaling $207.9 million, partially offset by repayments of long-term debt totaling $251.6 million.
|
| | | | | | | | | | | | |
| | Successor | | | Predecessor |
| (in thousands) | Six Months Ended
June 30, 2019 | | February 9, 2018
Through
June 30, 2018 | | | January 1, 2018
Through
February 8, 2018 |
| Cash provided by (used for) | | | | | | |
| Proceeds from long-term debt borrowings | $ | 183,500 |
| | $ | — |
| | | $ | 60,000 |
|
| Repayments of long-term debt | — |
| | (134,065 | ) | | | (43,000 | ) |
| Capital contributions (distributions), net | — |
| | 553,344 |
| | | (68 | ) |
| Other | — |
| | (1,366 | ) | | | — |
|
| Cash from financing activities | $ | 183,500 |
| | $ | 417,913 |
| | | $ | 16,932 |
|
During the 2019 period, our outstanding balance owed under the Alta Mesa RBL increased by $183.5 million from December 31, 2018, largely related to borrowings to fund of our capital expenditures, including those expenditures incurred in 2018.
Immediately following the Business Combination on February 9, 2018, we received a capital contribution from our immediate parent, SRII Opco, of $560.3 million, a portion of which was used to fund additional capital expenditures.
ITEMItem 3. Quantitative and Qualitative Disclosures about Market Risk
For information regarding our exposureWe are exposed 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”that are inherent in our 2017 Annual Report. Therefinancial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but we do not enter into derivatives for speculative purposes. We do not designate derivatives as hedges for accounting purposes.
Commodity Price Risk and Hedges
Our major market risk exposure is to prices for oil, gas and NGLs, which have historically been no materialvolatile. As such, future results are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional prices for gas. We have used, and expect to continue to use, derivatives to reduce our exposure to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Notes 8 and 9of price changes. Pursuant to our condensed consolidated financial statements forrisk management policy, we engage in these activities as a descriptionhedging mechanism against low prices and price volatility associated with developed and undeveloped reserves.
Forecasted production from proved reserves is estimated in our December 31, 2018 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, perhaps materially. Our Risk Factors in our 2018 10-K contain discussions of our outstanding derivative contracts at the most recent reporting date.significant matters related to future production.
The fair value of our commodity derivative contractsoil and gas derivatives and basis swaps at SeptemberJune 30, 20182019 was a net liabilityasset of $41.5$6.2 million. A 10% increase or decrease in oil naturaland gas and natural gas liquids prices with(with all other factors held constantconstant) would result in a decreasean unrealized loss or increase, respectively,gain in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity derivativeoil and gas derivatives for the six months ended June 30, 2019 of $7.7 million and $18.9 million, respectively.
Counterparty and Customer Credit Risk
Our derivatives expose us to credit risk in the event of nonperformance by counterparties. While we do not require them to post collateral, we do monitor the credit standing of such counterparties, all of which have investment grade ratings, and are lenders under the Alta Mesa RBL.
Our principal ongoing exposures to credit risk are from joint interest receivables and receivables from the sale of our oil and gas production. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit quality of our purchasers of production and other working interest owners is high.
During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving
payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019.
For the six months ended June 30, 2019, ARM marketed $91.5 million, (decreaseor 39.8% of our operating revenue for the period.
Joint operations receivables arise from billings to entities that own interests in value) or $31.2 million (increasethe wells we operate. These entities participate in value), respectively, as of September 30, 2018.our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
Interest Rates
We are subject to interest rate risk on our variable interest rate borrowings. Although inunder the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, weAlta Mesa RBL. We currently have no open interest rate derivative contracts.derivatives. A 1%100 basis point increase in interest rates would increase annual interest expense on our Eighth A&R credit facilitythe Alta Mesa RBL by $0.8approximately $3.4 million, based on the balance outstanding at SeptemberJune 30, 2018. 2019.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the 2019 period. Although the impact of inflation has been insignificant in recent years, it could cause future upward pressure on the cost of oilfield services, equipment and general and administrative expenses.
ITEMItem 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
In accordance withAs required by Rules 13a-15 and 15d-15 underof the Exchange Act, we carried out an evaluation, under the supervision andour management, with the participation of management, including our Chief Executive Officerprincipal executive officer and our Chief Financial Officer, of the effectivenessprincipal financial officer, performed an evaluation 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 disclosureprocedures. Our controls and procedures were effective as of September 30, 2018are designed to provide reasonable assuranceensure that information required to be disclosed by the Company in our reports filedit files or submittedsubmits 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 controlsforms of the SEC, and procedures include controls and procedures designed to ensure that the information required to be disclosed by the Company in reports filedthat it files or submittedsubmits under the Exchange Act is accumulated and communicated to ourthe Company’s management, including our Chief Executive Officerthe principal executive officer and Chief Financial Officer,principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
As described further in our 2018 10-K, we concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to existence of material weakness in our internal control over financial reporting (“ICFR”). Apart from the controls and procedures relating to accounting for business combinations, several of the material weaknesses in our ICFR continued to exist during the 2019 period. These material weaknesses include:
establishment of formal policies and procedures;
ineffective monitoring activities that span the Company to ensure that internal controls processes are functioning properly;
ineffective controls over the financial statement close and disclosure process; and
over-reliance on and ineffective controls over access to and changes involving critical worksheets.
Changes in Internal Control Over Financial Reporting (ICFR)
The internal controls over financial reporting that existed priorWhile we have made progress in multiple areas to improve ICFR, management is continuing to implement the Business Combination were reviewed by managementremediation plan described in anticipation of the Business Combination. Subsequentour 2018 10-K and continues to the Business Combination, our parent company, AMR, has continuedwork to analyze, evaluate and, where appropriate, make changes in controls and procedures in a manner commensurateconsistent with the size, complexity and scale of its operations subsequent to the Business Combination. Other than such
During the Second Quarter 2019, we have made access changes to payroll, production accounting, and enhancements, there have been noreserves systems to address material weaknesses identified during 2018. Testing to be conducted later in 2019 will determine whether these changes to system access will prove effective in our internal control over financial reporting duringremediating the three months ended September 30, 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
underlying material weakness.
PART II —- OTHER INFORMATION
ITEMItem 1. Legal Proceedings
See Part I, Item 1, Note 13 — CommitmentsWe are subject to legal proceedings, claims and Contingenciesliabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Because legal proceedings are inherently unpredictable and unfavorable resolutions could occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, we may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, and/or the ongoing discovery and development of information important to the matters. There have been no significant changes during the 2019 period to the matters described in Legal Proceedings in our condensed consolidated financial statements, which is incorporated in this item by reference.2018 10-K.
ITEMItem 1A. Risk Factors
We are subject to certainvarious risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors”uncertainties in the 2017 Annual Report.course of our business. There have been no material changes with respectduring the 2019 period to the risk factors discloseddescribed under Risk Factors in the 2017 Annual Report during the quarter ended September 30, 2018.our 2018 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None.
Item 3. Defaults Upon Senior Securities
None.
Item 4. Mine Safety Disclosures
Not applicable.
ITEMItem 5. Other Information
On November 13, 2018, Michael A. McCabe, Chief Financial Officer and Assistant Secretary, announced his plans to retire following more than 12 years of service. Mr. McCabe will remain with the Company to help ensure an orderly transition until the earlier of March 31, 2019 or a date to be determined by the Company. In connection with his departure, the Company has entered into a Separation Agreement with Mr. McCabe pursuant to which he is entitled to (i) vesting acceleration for his outstanding awards under the Company’s 2018 Long-Term Incentive Plan, (ii) 150% of his base salary in effect on the separation date, (iii) 150% of the greater of (x) his target bonus or (y) the amount of bonus paid for the year immediately preceding the year containing the separation date, and (iv) a lump sum payment of approximately $117,000, in each case in exchange for certain waivers and releases for the Company’s benefit. Mr. McCabe will also receive certain other benefits, such as continued coverage pursuant to the consolidated omnibus budget reconciliation Act of 1985, as set forth in the separation agreement. These payments will be paid to Mr. McCabe upon his departure.None.
ITEMItem 6. Exhibits
|
| |
Exhibit
Number | Description of Exhibit |
| 2.1 | 3.1Contribution Agreement, dated as of August 16, 2017, by and among High Mesa Holdings, LP, High Mesa Holdings GP, LLC, Alta Mesa Holdings, LP, Alta Mesa Holdings GP, LLC, Silver Run Acquisition Corporation II, and, solely for certain provisions therein, the Contributor Owners party thereto (incorporated by reference to Exhibit 2.1 to Alta Mesa Holdings, LP’s Form 8-K filed with the SEC on August 17, 2017 (File No. 333-173751)) |
| 3.1 | |
| 3.2 | |
| 3.3 | |
| 3.4 | |
| |
| |
| |
| |
| 4.1 | Indenture, dated December 8, 2016, by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp,.Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trusteeTrustee (incorporated by reference tofrom Exhibit 4.1 to Alta Mesa Holdings, LP'sLP’s current report on Form 8-K filed with the SEC on December 8, 2016 (File No. 333-173751)). |
| 4.2 | Master Assignment, Increase Agreement and Amendment No. 1 to CreditRegistration Rights Agreement, dated as of May 14, 2018 to the Eighth AmendedDecember 8, 2016, by and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower,Alta Mesa Finance Services Corp., the Guarantors named therein and Wells Fargo Bank, National Association,Securities, LLC, as administrative agent forrepresentative of the Lenders and as issuing Lender,Initial Purchasers (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the Lenders listed therein and Barclays Bank PLC.SEC on December 8, 2016 (File No. 333-173751)). |
| 10.1 | Amendment No. 2 to CreditSeparation Agreement dated as of August 13, 2018July 2, 2019 by and between Ronald J. Smith and Alta Mesa Services, LP (incorporated by reference from exhibit 10.1 to the Eighth Amended and Restated Credit Agreement dated as of February 9, 2018, among Alta Mesa Holdings, LP, as borrower, Wells Fargo Bank, National Association, as administrative agent forLP’s current report on Form 8-K filed with the Lenders and as issuing lender and the Lenders listed therein.SEC on July 8, 2019 (File No. 333-173751)). |
| 10.4 | |
| 31.1* | |
| 31.2* | |
| 32.1* | |
| 32.2* | |
| 101* | Interactive data files. |
|
* filed herewith.
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.
|
| | | |
| | ALTA MESA HOLDINGS, LP |
| | | By: Alta Mesa Holdings GP, LLC |
| | Its general partner |
| | (Registrant) |
| | | |
| | By: | ALTA MESA HOLDINGS GP, LLC, its
|
November 14, 2018By | | general partner |
| /s/ John C. Regan | | |
| | By: | /s/ Harlan H. Chappelle |
| | Harlan H. Chappelle |
| | President and Chief Executive Officer |
November 14, 2018John C. Regan | | |
| | By:Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | /s/ Michael A. McCabe | |
| | | Michael A. McCabe | |
| Dated | August 27, 2019 | | | Vice President and Chief Financial Officer |