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Texas | 20-3565150 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
15021 Katy Freeway, Suite 400, Houston, Texas | 77094 | |
(Address of principal executive offices) | (Zip Code) | |
| Large accelerated filer |
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| Non-accelerated filer |
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Smaller reporting company |
| Emerging growth company |
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| bbl - | Barrels |
| bbl/d - | Barrels per day |
| BOE - | Barrels of oil equivalent |
| Btu - | British thermal units |
| Completion - | The installation of permanent equipment for the production of oil and gas |
| EBITDAX - | Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses |
| Mbbls - | One thousand barrels |
| Mbbls/d - | One thousand barrels per day |
| MBoe/d - | One thousand barrels of oil equivalent per day |
| Mcf - | One thousand cubic feet |
| Mcf/d - | One thousand cubic feet per day |
| MMBtu - | One million British thermal units |
| MMcf - | One million cubic feet |
| MMcf/d - | One million cubic feet per day |
| NYMEX - | New York Mercantile Exchange |
| NGLs - | Natural gas liquids are a group of hydrocarbons including ethane, propane, normal butane, isobutane and natural gasoline |
| VWAP - | Volume weighted average price |
| Wellbore - | A hole that is drilled to aid in the exploration and recovery of natural resources including oil or natural gas |
| Working interest - | An interest in a mineral property that entitles the owner of that interest to all of the share of the mineral production from the property, usually subject to a royalty |
Successor Predecessor March 31, December 31, 2018 2017 ASSETS CURRENT ASSETS Cash and cash equivalents $ $ Short-term restricted cash Accounts receivable, net of allowance of $65 and $415, respectively Other receivables — Receivables due from affiliate — Receivables due from related party Note receivable due from related party — Prepaid expenses and other current assets Current assets — discontinued operations — Derivative financial instruments — Total current assets PROPERTY AND EQUIPMENT Oil and natural gas properties, successful efforts method, net Other property and equipment, net Total property and equipment, net OTHER ASSETS Deferred financing costs, net Notes receivable due from related party Deposits and other long-term assets Non-current assets — discontinued operations — Derivative financial instruments Total other assets TOTAL ASSETS $ $ LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES Accounts payable and accrued liabilities $ $ Accounts payable — affiliate Advances from non-operators Advances from related party Asset retirement obligations Current liabilities — discontinued operations — Derivative financial instruments Total current liabilities LONG-TERM LIABILITIES Asset retirement obligations, net of current portion Long-term debt, net Noncurrent liabilities — discontinued operations — Derivative financial instruments Other long-term liabilities Total long-term liabilities TOTAL LIABILITIES Commitments and Contingencies (Note 13) PARTNERS' CAPITAL TOTAL LIABILITIES AND PARTNERS' CAPITAL $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 OPERATING REVENUES AND OTHER Oil $ $ $ Natural gas Natural gas liquids Other revenues Total operating revenues Gain on sale of assets and other — — Gain (loss) on derivative contracts Total operating revenues and other OPERATING EXPENSES Lease operating expense Marketing and transportation expense Production taxes Workover expense Exploration expense Depreciation, depletion, and amortization expense Impairment expense — — Accretion expense General and administrative expense Total operating expenses INCOME (LOSS) FROM OPERATIONS OTHER INCOME (EXPENSE) Interest expense Interest income and other Total other income (expense) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES Provision for state income taxes — — INCOME (LOSS) FROM CONTINUING OPERATIONS LOSS FROM DISCONTINUED OPERATIONS, net of state income taxes — NET INCOME (LOSS) $ $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ $ $ Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities: Depreciation, depletion, and amortization expense Impairment expense — Accretion expense Amortization of deferred financing costs — Amortization of debt premium — — Equity based compensation expense — — Dry hole expense — — Expired leases (Gain) loss on derivative contracts Settlements of derivative contracts Interest converted into debt — Interest on notes receivable due from related party Loss on sale of assets and other — — Changes in assets and liabilities: Accounts receivable Other receivables Receivables due from affiliate — — Receivables due from related party Prepaid expenses and other current and non-current assets Advances from related party Settlement of asset retirement obligation Accounts payable — affiliate — — Accounts payable, accrued liabilities, and other liabilities NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for property and equipment NET CASH USED IN INVESTING ACTIVITIES CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term debt — Repayments of long-term debt — Additions to deferred financing costs — Capital distributions — — Capital contributions — NET CASH PROVIDED BY FINANCING ACTIVITIES NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, end of period $ $ $ eastern Anadarko Basin. As a result, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements. See As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. Successor Predecessor March 31, December 31, 2018 2017 Cash and cash equivalents $ $ Short-term restricted cash Cash of discontinued operations — Total cash, cash equivalents and restricted cash $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 Supplemental cash flow information: Cash paid for interest $ $ $ Non-cash investing and financing activities: Change in asset retirement obligations — Change in accruals or liabilities for capital expenditures Distribution of non-STACK assets (net liability) — — Successor Predecessor March 31, December 31, 2018 2017 Oil, natural gas and natural gas liquids sales $ $ Joint interest billings Pooling interest (1) Allowance for doubtful accounts Total accounts receivable, net $ $ 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 facility described in The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, 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. 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. The Successor Predecessor March 31, December 31, 2018 2017 OIL AND NATURAL GAS PROPERTIES Unproved properties $ $ Accumulated impairment of unproved properties — — Unproved properties, net Proved oil and natural gas properties Accumulated depreciation, depletion, amortization and impairment Proved oil and natural gas properties, net TOTAL OIL AND NATURAL GAS PROPERTIES, net OTHER PROPERTY AND EQUIPMENT Land Salt water disposal system — Office furniture and equipment, vehicles — Accumulated depreciation OTHER PROPERTY AND EQUIPMENT, net TOTAL PROPERTY AND EQUIPMENT, net $ $ Periods. Predecessor January 1, 2018 Three Through Months Ended February 8, 2018 March 31, 2017 Loss from Discontinued Operations Operating revenues and other: Oil $ $ Natural gas Natural gas liquids Other revenues Total operating revenues Loss on sale of assets — Total operating revenues and other Operating expenses: Lease operating expenses Marketing and transportation Production and ad valorem taxes Workover expense Exploration expense — Depreciation, depletion and amortization expense Impairment Accretion General and administrative expense Total operating expenses Interest expense Loss from discontinued operations, net of state income taxes $ $ Predecessor January 1, 2018 Three Through Months Ended February 8, 2018 March 31, 2017 Total operating cash flows of discontinued operations $ $ Total investing cash flows of discontinued operations MEASUREMENTS We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable inputs from the Level 1 Level 2 Level 3 Total (in thousands) At March 31, 2018: (Successor) Financial Assets: Derivative contracts for oil and natural gas — $ — $ Financial Liabilities: Derivative contracts for oil and natural gas — $ — $ At December 31, 2017: (Predecessor) Financial Assets: Derivative contracts for oil and natural gas — $ — $ Financial Liabilities: Derivative contracts for oil and natural gas — $ — $ As of September 30, 2018, we are not a party to any interest rate swap agreements. 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. March 31, 2018 (Successor) Net Fair Gross Gross amounts Value of Assets Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current assets $ $ $ — Derivative financial instruments, long-term assets Total $ $ $ Net Fair Gross Gross amounts Value of Liabilities Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current liabilities $ $ $ Derivative financial instruments, long-term liabilities Total $ $ $ December 31, 2017 (Predecessor) Net Fair Gross Gross amounts Value of Assets Fair Value offset against assets presented in Balance sheet location of Assets in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current assets $ $ $ Derivative financial instruments, long-term assets Total $ $ $ Net Fair Gross Gross amounts Value of Liabilities Fair Value offset against liabilities presented in Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet (in thousands) Derivative financial instruments, current liabilities $ $ $ Derivative financial instruments, long-term liabilities Total $ $ $ Successor Predecessor Derivatives not February 9, 2018 January 1, 2018 Three designated as hedging Through Through Months Ended instruments under ASC 815 March 31, 2018 February 8, 2018 March 31, 2017 Gain (loss) on derivative contracts Oil commodity contracts $ $ $ Natural gas commodity contracts Natural gas liquids commodity contracts — — Total gain (loss) on derivative contracts $ $ $ facility described in Volume Weighted Range Period and Type of Contract in Bbls Average High Low 2018 Price Swap Contracts $ $ $ Collar Contracts Short Call Options Long Put Options Short Put Options 2019 Collar Contracts Short Call Options Long Put Options Short Put Options 2020 Collar Contracts Short Call Options Long Put Options Short Put Options Volume in Weighted Range Period and Type of Contract MMBtu Average High Low 2018 Price Swap Contracts $ $ $ Collar Contracts Short Call Options Long Put Options Short Put Options 2019 Collar Contracts Short Call Options Long Put Options Short Put Options Weighted Average Spread Volume in MMBtu (1) Reference Price 1 (1) Reference Price 2 (1) Period ($ per MMBtu) 152,500 WAHA NYMEX Henry Hub Nov '18 — Dec '18 $ 225,000 WAHA NYMEX Henry Hub Jan '19 — Mar '19 Weighted Average Spread Volume in Bbl (1) Reference Price 1 (1) Reference Price 2 (1) Period ($ per Bbl) 1,104,000 CMA Oil WTI July '18 — Dec 18 $ 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 Successor Predecessor March 31, December 31, 2018 2017 Senior secured revolving credit facility $ — $ 7.875% senior unsecured notes due 2024 Unamortized premium on senior unsecured notes — Unamortized deferred financing costs — Total long-term debt, net $ $ 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 a current ratio, subject to various adjustments as defined in the Eighth A&R credit facility, tested quarterly, commencing with 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 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 255,701 3,660 1,295 1,269 98,648 76,161 1,388 895 7,892 790 1,578 5,303 2,932 5,195 216 371,312 91,611 2,389,522 920,563 46,823 6,207 2,436,345 926,770 1,007 1,787 11,039 12,369 8,627 9,067 43,785 49 8 20,722 67,016 2,828,379 1,085,397 147,764 170,489 3,651 5,476 1,312 5,502 40,498 23,390 622 69 15,419 26,401 19,303 220,248 239,648 6,033 10,400 532,815 607,440 66,862 2,916 1,114 1,935 5,488 543,699 691,304 763,947 930,952 2,064,432 154,445 2,828,379 1,085,397 Successor Predecessor September 30,
2018 December 31,
2017ASSETS CURRENT ASSETS Cash and cash equivalents $ 8,869 $ 3,660 Restricted cash 872 1,269 Accounts receivable, net 107,984 76,161 Other receivables 246 1,388 Receivables due from affiliate 16,656 — Receivables due from related party 13,085 790 Note receivable due from related party 1,642 — Prepaid expenses and other current assets 3,423 2,932 Current assets — discontinued operations — 5,195 Derivative financial instruments — 216 Total current assets 152,777 91,611 PROPERTY AND EQUIPMENT Oil and natural gas properties, successful efforts method, net 2,697,757 894,630 Other property and equipment, net 93,956 32,140 Total property and equipment, net 2,791,713 926,770 OTHER ASSETS Deferred financing costs, net 1,216 1,787 Notes receivable due from related party 11,492 12,369 Deposits and other long-term assets 86 9,067 Non-current assets — discontinued operations — 43,785 Derivative financial instruments — 8 Total other assets 12,794 67,016 TOTAL ASSETS $ 2,957,284 $ 1,085,397 3ALTA MESA HOLDINGS, LP AND SUBSIDIARIESCONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)(in thousands)40,278 30,972 46,940 5,210 4,276 9,591 4,714 4,000 7,072 555 888 1,234 50,757 40,136 64,837 5,979 (22,646) 7,298 30,242 34,090 47,434 95,079 8,317 4,485 11,010 5,582 3,725 5,662 1,415 953 1,266 1,245 423 588 4,955 3,633 5,047 10,936 11,784 18,978 1,188 102 39 96 31,459 24,352 9,736 64,011 49,394 53,571 (29,921) (1,960) 41,508 (5,196) (5,511) (12,042) 546 172 249 (4,650) (5,339) (11,793) (34,571) (7,299) 29,715 285 (34,571) (7,299) 29,430 (7,593) (4,515) (34,571) (14,892) 24,915 Successor Predecessor September 30,
2018 December 31,
2017LIABILITIES AND PARTNERS’ CAPITAL CURRENT LIABILITIES Accounts payable and accrued liabilities $ 227,139 $ 170,489 Accounts payable — affiliate 481 5,476 Advances from non-operators 9,233 5,502 Advances from related party 16,917 23,390 Asset retirement obligations 1,300 69 Current liabilities — discontinued operations — 15,419 Derivative financial instruments 34,396 19,303 Total current liabilities 289,466 239,648 LONG-TERM LIABILITIES Asset retirement obligations, net of current portion 9,169 10,400 Long-term debt, net 610,354 607,440 Noncurrent liabilities — discontinued operations — 66,862 Derivative financial instruments 7,078 1,114 Other long-term liabilities 5 5,488 Total long-term liabilities 626,606 691,304 TOTAL LIABILITIES 916,072 930,952 Commitments and Contingencies (Note 13) PARTNERS’ CAPITAL 2,041,212 154,445 TOTAL LIABILITIES AND PARTNERS’ CAPITAL $ 2,957,284 $ 1,085,397 4CHANGES IN PARTNERS’ CAPITALOPERATIONS (Unaudited)
PredecessorBALANCE, DECEMBER 31, 2017$154,445 DISTRIBUTION OF NON-STACK ASSETS (NET LIABILITY)33,102 NET LOSS(14,892)BALANCE, FEBRUARY 8, 2018$172,655 SuccessorBALANCE, FEBRUARY 9, 20181,535,891 CONTRIBUTION560,344 EQUITY BASED COMPENSATION2,768 NET LOSS(34,571)BALANCE, MARCH 31, 2018$2,064,432 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 OPERATING REVENUES AND OTHER Oil $ 107,253 $ 44,201 $ 222,822 $ 30,972 $ 133,489 Natural gas 11,959 9,583 25,149 4,276 29,816 Natural gas liquids 13,880 7,548 28,835 4,000 21,201 Other revenues 1,011 1,792 3,795 888 5,005 Total operating revenues 134,103 63,124 280,601 40,136 189,511 Gain (loss) on sale of assets and other (18 ) — 5,898 — — Gain on acquisition of oil and gas properties — 5,267 — — 5,267 Gain (loss) on derivative contracts (11,212 ) (10,468 ) (63,077 ) 7,298 38,024 Total operating revenues and other 122,873 57,923 223,422 47,434 232,802 OPERATING EXPENSES Lease operating expense 16,351 10,407 37,347 4,485 32,897 Marketing and transportation expense 15,820 8,314 32,608 3,725 20,486 Production taxes 6,311 1,262 10,332 953 3,712 Workover expense 1,065 1,441 2,643 423 3,131 Exploration expense 1,029 3,649 14,067 3,633 11,888 Depreciation, depletion and amortization expense 45,623 24,159 83,068 11,784 63,247 Impairment expense — — — — 1,188 Accretion expense 226 108 489 39 234 General and administrative expense 7,918 17,445 57,188 24,352 35,474 Total operating expenses 94,343 66,785 237,742 49,394 172,257 INCOME (LOSS) FROM OPERATIONS 28,530 (8,862 ) (14,320 ) (1,960 ) 60,545 OTHER INCOME (EXPENSE) Interest expense (11,008 ) (13,545 ) (26,565 ) (5,511 ) (38,165 ) Interest income and other 322 244 1,688 172 792 Total other income (expense), net (10,686 ) (13,301 ) (24,877 ) (5,339 ) — (37,373 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES 17,844 (22,163 ) (39,197 ) (7,299 ) 23,172 Provision for state income taxes — — 7 — 285 INCOME (LOSS) FROM CONTINUING OPERATIONS 17,844 (22,163 ) (39,204 ) (7,299 ) 22,887 Loss from discontinued operations, net of state income tax — (2,041 ) — (7,593 ) (37,490 ) NET INCOME (LOSS) $ 17,844 $ (24,204 ) $ (39,204 ) $ (14,892 ) $ (14,603 ) 5CASH FLOWSCHANGES IN PARTNERS’ CAPITAL (Unaudited)(34,571) (14,892) 24,915 10,936 12,414 24,804 5,560 1,220 102 140 572 171 962 (820) 2,768 (45) 4,189 1,250 3,333 22,646 (7,298) (30,242) (4,610) (1,661) (1,970) 103 298 (162) (85) (200) 1,923 3,097 (20,895) (5,374) 1,222 (9,887) 7,494 (895) (6,985) (117) 139 (2,240) 9,970 (9,543) (7,008) 24,116 (29,791) (166) (63) (2,394) (1,824) (34,990) 25,815 11,837 (49,311) 26,519 (3,940) (129,310) (38,096) (60,589) (129,310) (38,096) (60,589) 60,000 55,065 (134,065) (43,000) (1,007) (64) (68) 560,344 7,875 425,272 16,932 62,876 246,651 5,355 (1,653) 10,345 4,990 7,618 256,996 10,345 5,965 Successor Predecessor Three Months Ended
September 30, 2018 February 9, 2018 Through September 30, 2018 Three Months Ended
September 30, 2017 January 1, 2018 Through February 8, 2018 Nine Months Ended
September 30, 2017Beginning balance $ 2,048,043 $ 1,535,891 $ 41,707 $ 154,445 $ 32,106 Distribution of non-stack (assets) net liability — — — 33,102 — Capital contributions — 560,344 200,000 — 200,000 Distributions (25,000 ) (32,000 ) — — — Issuance of additional Alta Mesa purchase consideration — 9,467 — — — Equity-based compensation expense 325 6,714 — — — Net income (loss) 17,844 (39,204 ) (24,204 ) (14,892 ) (14,603 ) Ending balance $ 2,041,212 $ 2,041,212 $ 217,503 $ 172,655 $ 217,503 6 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 (Unaudited)1.— DESCRIPTION OF BUSINESSandtogether with its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”), is an independent exploration and production company engaged primarily infocused on the acquisition, development, exploration development, and productionexploitation of unconventional onshore oil and natural gas propertiesreserves 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 STACK. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County –(“STACK”). multiple, stacked productive formations presentperiod 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”).area. Successor Predecessor September 30,
2018 December 31,
2017Cash 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 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 September 30,
2018 December 31,
2017Oil, natural gas and natural gas liquids sales $ 40,134 $ 26,916 Joint interest billings 44,548 13,821 23,367 35,839 Allowance for doubtful accounts (65 ) (415 ) Total accounts receivable, net $ 107,984 $ 76,161 (1) Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents costs of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties. Alta Mesa Resources, Inc. (“AMR”)AMR (formerly Silver Run Acquisition Corporation II), High Mesa Holdings, LP (the “AM Contributor”),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”). AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, was controlled by High Mesa Inc. (“High Mesa”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.In connection with the closing of the Business Combination, we distributed the remainder of our non-STACK assets to the AM Contributor and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. Refer to Note 5—Business Combination for further information related to the Business Combination.2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESWe 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 March 31, 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 PresentationThe accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information 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 footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances.7The condensed consolidated financial statements included herein as of March 31, 2018, and for the period from February 9. 2018 through March 31, 2018 (Successor), January 1, 2018 through February 8, 2018 (Predecessor) and the three months ended March 31, 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 consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 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 periods are not necessarily indicative of results to be expected for a full year. As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree. Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations, (“ASC 805”), the 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 assets and liabilities being recorded at fair value as of the acquisition date. As a result of the impact of electing pushdown accounting, 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 period presented herein is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and for the three months ended March 31, 2017 (“2017 Predecessor Period”).The Company’s 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 other items of 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.As noted above, we distributed the remainder of our non-STACK assets to the AM Contributor in connection with the closing of the Business Combination. The distribution of our remaining non-STACK assets and the sale of our Weeks Island field during the fourth quarter 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, the Predecessor assets and liabilities and operating results directly related to non-STACK assets are presented as discontinued operations within the consolidated statement of operations. See Note 7 — Discontinued Operations for further discussion.Use of EstimatesThe 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.Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, 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.Bond Premium on Senior Unsecured NotesAs result of the push down accounting related to the Business Combination, the Company estimated the fair value of our $500 million senior unsecured notes at $533.6 million as of the acquisition date. The amount in excess of the principal amount was recorded as a bond premium, which is being amortized over the term of the notes using the straight-line method, which approximates the effective interest method. 8Equity Based Compensation (Successor)The Company recognizes compensation related to all stock-based awards, including awards of AMR stock and stock options, in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options and restricted stock. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock awards 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 (Successor).Restricted CashThe 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):255,701 3,660 1,295 1,269 61 256,996 4,990 Recent Accounting PronouncementsIn 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. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications 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. ASU 2014-09 and related interpretive guidance will be 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. The standard 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 have elected to use the extended transition period and as a result, we will be required to adopt the standard during the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We applied push down accounting to reflect AMR’s basis and accounting policies in our financial statements from the date of the Business Combination. If AMR loses its emerging growth company status in 2018, we would adopt the standard in the fourth quarter of 2018.We are in the process of assessing our contracts and evaluating the impact on the 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 future revenues and expenses under the new gross-versus-net presentation guidance. We continue to evaluate the impact of these and other provisions of ASU 2014-09 on our accounting policies, changes to relevant business practices, internal controls, and consolidated financial statements.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 (with the exception of 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 January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), 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 will be effective for interim and annual periods beginning after December 15, 2018 for public companies and annual periods beginning after December 15, 2019 for all other entities, with earlier adoption permitted. 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.9At this time, we cannot reasonably estimate the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and impletion 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 is also expected to result in increase in depreciation, depletion and amortization expense, interest expense recorded on our consolidated statement of operations, and additional disclosures. As part of our assessment to date, we have formed an implementation work team and will complete our evaluation in 2018. As we continue to evaluate and implement the standard, we will provide additional information about the expected financial impact at a future date. As an emerging growth company we have elected to use the extended transition period and as a result, we will be required to adopt the standard in 2020. AMR is also an emerging growth company. It is reasonably possible that AMR could cease to be an emerging growth company by December 31, 2018. We applied push down accounting to reflect AMR’s basis and accounting policies in our financial statements from the date of the Business Combination. If AMR loses its emerging growth company status in 2018, we would adopt the standard on January 1, 2019.In May 2017, the FASB issued ASU No. 2017-09, Compensation – Stock Compensation: Scope of Modification Accounting (“ASU 2017-09”), which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. ASU 2017-09 requires entities to account for the effects of a modification unless the fair value, vesting conditions, and classification of the modified award are all the same as the original award immediately before the original award is modified. ASU 2017-09 is effective prospectively for interim and annual reporting periods beginning after December 15, 2017. The Company adopted ASU 2017-09 in the first quarter of 2018; however, the adoption of ASU No. 2017-09 did not have a material impact on the Company's consolidated financial statements.3. SUPPLEMENTAL CASH FLOW INFORMATIONSupplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands):1,092 1,145 1,162 421 296 (36,866) 4,712 21,111 33,102 4. ACCOUNTS RECEIVABLEAccounts receivable consisted of the following (in thousands):27,890 26,916 33,197 13,821 37,626 35,839 (65) (415) 98,648 76,161 _________________(1)Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represent costs of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.5. BUSINESS COMBINATIONAs discussed in Note 1, on February 9, 2018, we consummated the Transactions contemplated by the AM Contribution Agreement.10Pursuant to the AM Contribution Agreement, SRII Opco acquired (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. 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 AMR 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”), corresponding to the number of Common Units received by the AM Contributor at closing. The Common Units of SRII Opco and corresponding Class C Common Stock issued to the AM Contributor are redeemable for AMR’s Class A Common Stock or cash (at AMR’s election) beginning 180 days after closing.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 contributions 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 balancesbalance under the senior secured revolving credit facility.statement. Subsequent tostatement during the second quarter end, it was determined thatof 2018. Based on the final closing statement, the AM Contributor would receive a positive adjustment amount and be issuedreceived an additional 1,197,934 additional SRII Opco Common Units and an equivalent number of shares of AMR’s Class C Common Stock.(“(“ASC 820”). ASC 805 requires, among other things, that allour 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 analyses areanalysis is performed. Pursuant to ASC 805, finalization of the values areis to be completed within one year of the Acquisition Date.acquisition date.11iswas as follows:follows (in thousands): February 9, 2018 (As adjusted) $ 1,251,782 $ 9,467 $ 1,261,249 284,109 — 284,109 Total purchase price consideration $ 1,535,891 $ 9,467 $ 1,545,358 (1) SuccessorAt February 9,2018(in thousands)Preliminary Purchase Consideration: (1)(158,402,398 valued at approximately $7.90 per unit) (2)$1,251,782 Estimated fair value of contingent earn-out purchase consideration (3)284,109 Total purchase price consideration$1,535,891 _________________(1)The preliminary purchase price consideration does not include the effects of the final closing statement adjustments, which adjustments were determined subsequent to March 31, 2018.(2)(3) (3)(4) usingas 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. dollarsdollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life. following table summarizes the allocation of AMR’s preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in connection with the acquisition of Alta Mesa in the Business Combination. The allocation iswas as follows:12 February 9, 2018 (As adjusted) 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 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 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 5,998 — 5,998 Derivative financial instruments 11,585 — 11,585 667,700 — 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 (1) At February 9,(2) 2018(in thousands)Estimated Fair Value of Assets Acquired (1)Cash, cash equivalents and short term restricted cash$10,345 Accounts Receivable101,745 Other Receivables1,222 Receivables due from related party907 Prepaid expenses and other current assets1,405 Derivative financial instruments352 Property and equipment: (2)Oil and natural gas properties, successful efforts2,314,858 Other property and equipment, net43,318 Notes receivable due from related party12,454 Deposits and other long-term assets10,286 Total fair value ofThe assets acquired2,496,892 Estimated Fair Value of Liabilities Assumed (1)Accounts payable and accrued liabilities210,867 Accounts payable — affiliate5,476 Advances from non-operators6,803 Advances from related party47,506 Asset retirement obligations5,998 Derivative financial instruments11,585 Long-term debt (3)667,700 Other long-term liabilities5,066 Total fair value of liabilities assumed961,001 Total consideration and fair value$1,535,891 _________________(1)The preliminary purchase price is allocated based on relate to Alta Mesa’s STACK Assets.(2)(3) fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. Theestimated fair values of oil and natural gas properties and asset retirement obligations were measureddetermined using valuation techniques that convert future cash flows to a single discounted amount.amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs to the valuation of oil and natural gas properties include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discountsdiscount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive andvaluation. Actual results may be subject to change.(3)(4) $500$500.0 million aggregate principal amount of the 7.875% senior unsecured notes due December 15, 2024, usingtotaling approximately $533.6 million, based on Level 1 inputs, as of the acquisition date of approximately $533.6 million, and outstanding borrowings under the senior secured revolvingEighth A&R credit facility (described in Note 11 — Long-Term Debt, Net) of $134.0approximately $134.1 million as of the acquisition date.13consistsconsisted of the following (in thousands):899,465 84,590 899,465 84,590 1,500,830 1,092,095 (10,773) (256,122) 1,490,057 835,973 2,389,522 920,563 4,413 2,912 42,573 20,008 (163) (16,713) 46,823 6,207 2,436,345 926,770 Successor Predecessor September 30,
2018 December 31,
2017OIL 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 –— Business Combination for details).7.As discussed in Note 1, we (Predecessor) the remainder of our non-STACK assets and related liabilities to the AM Contributor in connection withimmediately prior to the closingClosing Date of the Business Combination. The distribution of our remaining non-STACK assets and related liabilities during the first quarter of 2018 and the sale of our Weeks Island field during the fourth quarter of 2017 completed the Company’swere part of our overall strategic shift to operate only in the eastern Anadarko Basin. As a result, the Predecessor’s non-STACK assets and liabilities have been presented as discontinued operations in 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 Period. bearbore simple interest at 10%. In connection with the Transactions described in Note 1,5 –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 assetsasset 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.Period, respectively.14have been reclassified to assets and liabilities associated withpresented as discontinued operations in the condensed consolidated balance sheets were as follows (in thousands):
PredecessorDecember 31,2017Assets associated with discontinued operations:Current assetsCash$61 Accounts receivable4,980 Other receivables154 Total current assets5,195 Noncurrent assetsInvestments in LLC - Cost9,000 Proved oil and natural gas properties, net15,408 Unproved properties, net15,504 Land2,706 Other long-term assets1,167 Total noncurrent assets43,785 Total assets associated with discontinued operations$48,980 Liabilities associated with discontinued operations:Current liabilitiesAccounts payable and accrued liabilities$7,882 Asset retirement obligations 7,537 Total current liabilities15,419 Noncurrent liabilitiesAsset retirement obligations, net of current37,049 Founder's note28,166 Other long-term liabilities1,647 Total noncurrent liabilities66,862 Total liabilities associated with discontinued operations$82,281 15 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 of operations ofdirectly related to the non-STACK assets and other items directly related toliabilities presented as discontinued operations within the sale of the non-STACK assets have been reclassified in discontinued operationscondensed consolidated financial statements were as follows (in thousands):1,617 12,405 1,023 3,094 236 547 16 116 2,892 16,162 (1,923) 969 16,162 1,770 7,960 83 381 167 1,802 127 795 3,095 630 5,826 5,560 32 101 476 21 12 8,459 20,379 (103) (298) (7,593) (4,515) Predecessor Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017Operating 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 ) arewere as follows (in thousands):(6,838) 738 (570) (910) 8. Predecessor Nine Months Ended
September 30, 2017Total operating cash flows of discontinued operations $ (6,838 ) $ 16,166 Total investing cash flows of discontinued operations (570 ) (15,950 ) DISCLOSURES“Fair Value Measurements and Disclosures” (“ASC 820”). ASC 820which provides a hierarchy of fair value measurements based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.The fair valuethe Business Combination,our acquisition, we recorded the fair value of our $500$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 $520.6$476.3 million at March 31, 2018.September 30, 2018 (Successor). This estimation iswas 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 Debt, Net for information on long-term debt.16New York Mercantile Exchange (“NYMEX”)NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the inputs used to determine fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.OilDuring 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 for the 2017 Predecessor Period. Significantmillion. 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.properties, andproperties. Such estimations of fair values for them are categorized as Level 3. Such estimationsvalue 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 $0.4$1.7 million, zero and $0.3$1.0 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively.March 31,September 30, 2018 and December 31, 2017, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:4,481 4,481 33,749 33,749 4,416 4,416 24,609 24,609 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 Presentation on our consolidated balance sheets utilizes nettingWe 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.9.InstrumentsWe account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging” (“ASC 815”). We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our hedging agreementsderivative 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)(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)(gal) per month.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. 171,539 (1,539) 2,942 (2,893) 49 4,481 (4,432) 49 27,940 (1,539) 26,401 5,809 (2,893) 2,916 33,749 (4,432) 29,317 September 30, 2018 (Successor) (in thousands) 1,406 (1,190) 216 $ 2,407 $ (2,407 ) $ — 3,010 (3,002) 8 3,263 (3,263 ) — 4,416 (4,192) 224 $ 5,670 $ (5,670 ) $ — 20,493 (1,190) 19,303 4,116 (3,002) 1,114 24,609 (4,192) 20,417 18Balance sheet location (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 (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 (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 (22,579) 5,431 26,085 (67) 1,867 3,899 258 (22,646) 7,298 30,242 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 so long as we are not a defaulting party, after a default or the occurrence of a termination event,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.inon payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedgederivative could be lost. The value of our derivative financial instruments would be impacted.March 31,September 30, 2018:1,832,000 53.22 61.26 50.27 1,559,000 61.09 64.60 60.50 1,559,000 51.18 60.00 50.00 1,559,000 41.48 52.50 40.00 1,788,500 61.84 65.35 56.50 1,971,000 50.00 50.00 50.00 1,971,000 38.43 40.00 37.50 183,000 60.20 60.20 60.20 549,000 50.67 51.00 50.00 549,000 40.00 40.00 40.00 19 Range Settlement Period and Type of Contract High Low 2018 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 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 March 31,September 30, 2018:4,280,000 2.80 2.85 2.75 1,985,000 3.30 3.75 3.14 1,680,000 2.82 2.90 2.75 610,000 2.40 2.40 2.40 1,350,000 3.47 3.75 3.30 900,000 2.90 2.90 2.90 900,000 2.40 2.40 2.40 Range Settlement Period and Type of Contract High Low 2018 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 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 March 31,September 30, 2018:(1.05) (1.05) Period 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) WAHA OneOK, Tex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.(0.54) Period 552,000 CMA Oil WTI Oct '18 — Dec '18 $ (0.54 ) (1) pricing.20NOTE 10 10.— ASSET RETIREMENT OBLIGATIONS2018Balance, as of January 1 (Predecessor)$10,469 Liabilities settled(63)Revisions to estimates63 Accretion expense39 Balance, as of February 8 (Predecessor)10,508 Balance, as of February 9 (Successor)$ —Liabilities assumed from Business Combination5,998 Liabilities incurred421 Liabilities settled(166)Revisions to estimates300 Accretion expense102 Balance, as of March 31 (Successor)6,655 Less: Current portion622 Long-term portion$6,033 11. 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 ) 3,562 Accretion expense 489 Balance, as of September 30 (Successor) 10,469 Less: Current portion 1,300 Long-term portion $ 9,169 consistsconsisted of the following (in thousands):117,065 500,000 500,000 32,815 (9,625) 532,815 607,440 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 1)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 untilmillion. This borrowing base was reaffirmed by the lenders subsequent to September 30, 2018. The next scheduled redetermination will occur in October 2018.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, if we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of March 31,September 30, 2018, we have nohad $80.0 million of borrowings outstanding under the Eighth A&R credit facility and have $13.6had $21.9 million of outstanding letters of credit, reimbursement obligations.leaving a total borrowing capacity of $298.1 million remaining available for future use.and one month, three month or, six month periods for Eurodollar loans.loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, at the LIBOR, plus an applicablea margin ranging from 2.00% andto 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 andor (iii) the rate for one monthone-month Eurodollar loans plus 1%1.00%, plus a margin ranging from 1.00% to 2.00%. The next scheduled redetermination of our borrowing base is in October 2018. The borrowing base may be reduced in connection with the next redetermination of our borrowing base. capital stockcollateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.21expenses that are 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. We can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.· the fiscal quarter ending 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 ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) annualized by multiplying EBITDAX for the period of (A) the fiscal quarter ending June 30, 2018 times 4, (B) the two fiscal quarter periods ending 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 times 4/4ths, of not greater than 4.0 to 1.0.We will be required to maintain financial ratios commencing on the fiscal quarter endingended June 30, 2018.$500$500.0 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 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. year, beginning June 15, 2017.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 infor an amount of cash not greater than the net cash proceeds from certain equity offerings at thea 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.22as 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 (Successor) to the consolidated condensed financial statements for further detail.
| default in any payment of interest on |
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The credit facility and the senior notes contain customarywhen due, continued for 30 days;
12.
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| Successor |
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| Predecessor | ||
| March 31, |
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| December 31, | ||
| 2018 |
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| 2017 | ||
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Capital expenditures | $ | 48,767 |
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| $ | 48,771 |
Revenues and royalties payable |
| 31,684 |
|
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| 29,514 |
Operating expenses/taxes |
| 20,080 |
|
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| 14,632 |
Interest |
| 11,607 |
|
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| 2,587 |
Derivative settlement payable |
| 2,826 |
|
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| 2,106 |
Other |
| — |
|
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| 4,301 |
Total accrued liabilities |
| 114,964 |
|
|
| 101,911 |
Accounts payable |
| 32,800 |
|
|
| 68,578 |
Accounts payable and accrued liabilities | $ | 147,764 |
|
| $ | 170,489 |
| | 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 | ||||
13.— COMMITMENTS AND CONTINGENCIES
On March 12, 2018, the class settlement was approved by the Court.
ourselves.
24
Nonqualified Deferred Compensation.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.
14. SIGNIFICANT RISKS AND UNCERTAINTIES
15.
16. EQUITY BASED
Equity based compensation (Successor)
25
Stock options.
Options that have been granted under the LTIP expire seven years from the grant date and have service-based vesting schedulesgenerally vest in one-third increments each year on the anniversary date following the date of three years.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. On the Closing Date, AMR granted 4,082,571 stock options to the Company’s employees.
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| 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 |
| — |
| $ | — |
| — |
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| — |
Granted |
| 4,082,571 |
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| 4.62 |
| 4.3 |
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| — |
Exercised |
| — |
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| — |
| — |
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| — |
Forfeited or expired |
| — |
|
| — |
| — |
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| — |
Outstanding as of March 31, 2018 |
| 4,082,571 |
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| 4.62 |
| 4.3 |
| $ | 18,849 |
Exercisable as of March 31, 2018 |
| — |
| $ | — |
| — |
| $ | — |
| | 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 | — | $ | — | — | $ | — | |||||||
| ||||
| Successor | ||||
February 9, 2018 Through September 30, 2018 | ||||
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Expected term (in years) | 4.5 | |||
Expected stock volatility | 64.6 | |||
Dividend yield | — |
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Risk-free interest rate | 2.4 | |||
On February 9, 2018, 1,133,134 restricted stock were deemed
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| Awards |
| Weighted Average Grant - Date Fair Value per share | ||
Service-based stock awards: |
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Outstanding as of February 9, 2018 |
| — |
| $ | — |
Granted |
| 1,133,134 |
|
| 8.94 |
Vested |
| — |
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| — |
Forfeited or expired |
| — |
|
| — |
Outstanding as of March 31, 2018 |
| 1,133,134 |
| $ | 8.94 |
| | 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 | |||
Restricted stock units
On February 9, 2018, 0.7 million. The Company also grants performance-based restricted stock units (“PSUs”) were deemed granted to key employees under the LTIP. ForPSUs granted during the PSUs,period will vest over three years at 20% vest on December 31, 2018,during the first year, 30% vest on December 31, 2019during the second year and 50% vestduring the third year. The number of PSUs vesting each year will be based on December 31, 2020; provided that the actualachievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that are deemed granted and may be earned is betweenvest can range from 0% andto 200% of the initial target withgrant applicable to each vesting period. For accounting purposes, the final numberCompany will only recognize PSUs granted when the specified performance thresholds for future periods have been established. For PSUs granted during the period February 9, 2018 to be dependent upon achievement of certainSeptember 30, 2018, only the performance goals and objectives. Theobjectives for 2018 have been established to date. Those 2018 performance criteria with respectgoals are related to the PSUs that vestCompany achieving a specified level of EBITDAX for the period ended December 31, 2018 is based on our cumulative EBITDAX, as defined in the PSU grant agreement. The performance criteria for PSUs that vest in 2019 and 2020 have not yet been established and, accordingly, those PSUs were not deemed granted as of March 31, 2018 for expense recognition purposes. During the restriction period, the RSUs may not be transferred or encumbered, and the recipient does not receive dividend equivalents or have voting rights until the unit vests.
2018.
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| Successor | ||||
| RSUs |
| Weighted Average Grant - Date Fair Value per unit | ||
Outstanding as of February 9, 2018 |
| — |
| $ | — |
Granted |
| 710,974 |
|
| 8.94 |
Vested |
| — |
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| — |
Forfeited or expired |
| — |
|
| — |
Outstanding as of March 31, 2018 |
| 710,974 |
| $ | 8.94 |
| | 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 | |||
17.the marketing fees.
18.
Extended lease agreementEVENTS. On April 1,
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 Combination Three Months Ended 2018 March 31, Jan-18 Feb-18 Mar-18 2018 2017 Change % Average NYMEX daily prices: Oil (per bbl) $ $ $ $ $ $ Natural gas (per MMBtu) (7)% As of Successor Predecessor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 Net Revenues (in thousands, except per unit data) Oil sales $ $ $ Natural gas sales Natural gas liquids sales Total Net Revenues Net production: Oil (MBbls) Natural gas (MMcf) NGL's (MBbls) Total (MBoe) Average net daily production volume: Oil (MBbls/d) Natural gas (MMcf/d) NGL's (MBbls/d) Total (MBoe/d) Average sales prices: Oil (per Bbl) $ $ $ Effect of derivative settlements on average price (per Bbl) Oil net of hedging (per Bbl) $ $ $ Natural gas (per Mcf) $ $ $ Effect of derivative settlements on average price (per Mcf) Natural gas net of hedging (per Mcf) $ $ $ Natural gas liquids (per Bbl) $ $ $ Effect of derivative settlements on average price (per Bbl) — — Natural gas liquids net of hedging (per Bbl) $ $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 Gain(loss) on derivative contracts (in thousands): Oil $ $ $ Natural gas Natural gas liquids — — Total cash settlements Valuation changes Total gain (loss) on derivative contracts $ $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 Operating Expenses (in thousands, except per unit data): Lease operating expense $ $ $ Marketing and transportation expense Production taxes Production cost per BOE: Lease operating expense $ $ $ Marketing and transportation expense Production taxes Note 17 — Related Party Transactions for further detail. Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 (in thousands) Geological and geophysical costs $ $ $ Exploratory dry hole costs — — Exploration expense Loss on ARO settlement Total exploration expense $ $ $ Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 (in thousands) Depreciation, depletion and amortization $ $ $ Depreciation, depletion and amortization per BOE Successor Predecessor February 9, 2018 January 1, 2018 Three Through Through Months Ended March 31, 2018 February 8, 2018 March 31, 2017 (in thousands) Equity based compensation expense $ $ — $ — General and administrative expenses Total general and administrative expenses $ $ $ Successor Predecessor Predecessor February 9, 2018 January 1, 2018 Through Through Three Months Ended March 31, 2018 February 8, 2018 March 31, 2017 (in thousands) Interest expense $ $ $ Senior secured revolving credit facility — Senior unsecured notes Other Total interest expense $ $ $ As of As of 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. Changes in Internal Control Over Financial Reporting three months ended September 30, 2018 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 101* Interactive data files. * filed herewith. ALTA MESA HOLDINGS, LP (Registrant) general partner /s/ Harlan H. Chappelle Harlan H. Chappelle President and Chief Executive Officer /s/ Michael A. McCabe Michael A. McCabe Vice President and Chief Financial Officerbelow in “Cautionary Statement Regarding Forward-Looking Statements,” at the beginning of this Quarterly Report and in our 2017 Annual Report, particularly in the section titled “Risk Factors,” all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.We have been engaged inonshore oil“Company,” and natural gas acquisition, exploitation,“Alta Mesa”) is an independent exploration and production in the United States since 1987. Currently we are focusingcompany focused on the acquisition, development, exploration and acquisitionexploitation of unconventional onshore oil and natural gas reserves in the STACK. We transitioned our focus from our prior diversified asset base composedeastern portion of a portfoliothe Anadarko Basin in Oklahoma. Our activities are primarily directed at the horizontal development of conventional assets to an oil and liquids-rich resource play in an area of the STACK with an extensive inventory of drilling opportunities. The STACK is a prolific hydrocarbon system with high oil and liquids-rich natural gas content, multiple horizontal target horizons, extensive production history and historically high drilling success rates. The STACK is an acronym describing both its location –basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area.(“STACK”). We maintain operational control of the majority of our properties, either through directly operating them or through operating arrangements with other interest owners.Business CombinationOn August 16, 2017, we entered into a Contribution Agreement (the “AM Contribution Agreement”) with Alta Mesa Resources, Inc. (“AMR”) (formerly Silver Run Acquisition Corporation II, a Delaware corporation, High Mesa Holdings, LP, a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company and the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, a Texas limited liability company and our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor. Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement (the “KFM Contribution Agreement”) 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; 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”).On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreements and SRII Opco, LP, a Delaware limited partnership (“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 pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.”SRII Opco GP, LLC, a Delaware limited liability company (“SRII Opco GP”), the sole general partner of SRII Opco, is a wholly owned subsidiary of AMR. The limited partners of SRII Opco are the AM Contributor, the KFM Contributor and the Riverstone Contributor (collectively, the “Contributors”), AMR and certain funds managed by Highbridge. As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. AMR is a publicly traded corporationother transactions that is not under the control of any person. Prior to the closing of the Transactions, AMH GP, and consequently, us, were controlled by High Mesa and indirectly by our founder and Chief Operating Officer, Michael E. Ellis.28Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company (“Bayou City”), and HPS Investment Partners, LLC, a Delaware limited liability company (“Highbridge”), continue to own an aggregate 10% voting interest in AMH GP following the closing. These existing owners were a party to a voting agreement with the AM Contributor and AMH GP, pursuant to which they agreed to vote their interests in AMH GP as directed by the AM Contributor. In connection with the closing of the Transactions, the parties amended and restated the voting agreement to include SRII Opco as a party and the existing owners agreed to vote their interests in AMH GP as directed by SRII Opco and appoint SRII Opco as their respective proxy and attorney-in-fact with respect to any voting matters related to their respective interests in AMH GP. The amended and restated voting agreement will continue in force until SRII Opco elects to terminate the agreement or, with respect to each existing owner individually, such existing owner no longer owns a voting interest in AMH GP.ConsiderationPursuant to the AM Contribution Agreement, at the closing of the Transactions (the “Closing”), 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 AMR 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”), corresponding to the number of Common Units received by the AM Contributor at the Closing. In addition to the above, 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”):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 contributions 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 balances under the senior secured revolving credit facility. Pursuant to the AM Contribution Agreement, the AM Contributor delivered a final closing statement. Subsequent to quarter end, it was determined that the AM Contributor would receive a positive adjustment amount and be issued 1,197,934 additional Common Units and an equivalent number of shares of AMR’s Class C Common Stock. Exchange or Redemption of Common UnitsBeginning 180 days after the Closing, the AM Contributor will have the right to exchange its Common Units for shares of AMR Class A Common Stock or cash (at AMR’s election). Upon any redemption of Common Units by the AM Contributor, a corresponding number of shares of Class C Common Stock owned by the AM Contributor will be cancelled.Amended Limited Partnership and Limited Liability Company AgreementIn connection with the closing of the Business Combinationoccurred on February 9, 2018, AMH GP and SRII Opco entered into a Seventh Amended and Restated Agreement of Limited Partnership of Alta Mesa (the “Seventh Amended Partnership Agreement”). The Seventh Amended Partnership Agreement reflects, among other things, that SRII Opco is now our sole limited partner.29In addition, on February 9, 2018, the owners of AMH GP entered into a Sixth Amended and Restated Limited Liability Company Agreement of AMH GP, which was amended to, reflect that SRII Opco, now the holder of all of the Class A Units (as defined therein) is entitled to 100% of the economic rights with respect to AMH GP, and that SRII Opco is now the holder of 90% of the Class B Units (as defined therein) which are entitled to 100% of the voting rights with respect to AMH GP.As described above, on February 9, 2018, all of the owners of AMH GP entered into an amended and restated voting agreement regarding the voting of their interestsmay be found in AMH GP.Appointment and Departure of DirectorsIn connection with the Business Combination, Michael A. McCabe, Homer “Gene” Cole, Mickey Ellis, Don Dimitrievich, William W. McMullen and Mark Stoner resigned from the board of AMH GP. In connection with the Business Combination, James T. Hackett was appointed to the board of AMH GP. Harlan H. Chappelle and Michael E. Ellis remain directors on the board of AMH GP. Our executive management team remains the same, except that Mr. Hackett is now Chairman of the Board.Amended and Restated Senior Secured Revolving Credit FacilityIn connection with the closing of the Business Combination, 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. 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 our financial covenants. As of February 9, 2018, all outstanding balances under our credit facility were paid in full. For further details of the Business Combination please see Note 5 — Business Combinations in the consolidated financial statements.Distribution of Non-Stack AssetsIn connection with the closing of the Business Combination, we completed our transition from a diversified asset base composed of a portfolio of conventional assetsNotes to an oil and liquids-rich resource play in the STACK with an extensive inventory of drilling opportunities. On February 8, 2018, we distributed the remainder of our non-STACK assets to AM Contributor as a dividend. We also converted the Founder Notes into equity interest in the AM Contributor immediatelyCondensed Consolidated Financial Statements. Immediately prior to the closing of the Business Combination as they were considered part of the non-STACK assets. 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 for the 2017 Predecessor Period.Presentation of Financial and Operating DataAs a result of the Business Combination, AMR was treated as the accounting acquirer andbusiness combination described in Note 5, we are the accounting acquiree and the accounting predecessor of AMR. Pursuant to Accounting Standard Codification (“ASC”) 805, Business Combinations (“ASC 805”), the identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the acquisition date. Fair value adjustments related to the transaction have been pushed down to us resulting in assets and liabilities being recorded at fair value as of the acquisition date. As a result of the impact of electing pushdown accounting, 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 period is from February 9, 2018 to March 31, 2018 (“Successor Period”) and the Predecessor periods are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”) and for the three months ended March 31, 2017 (“2017 Predecessor Period”).The Company’s 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 other items of 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.As noted above, we distributed the remainder of our non-STACK assets and related liabilities to the AM ContributorHigh Mesa Holdings, LP (the “AM Contributor”), which is more fully described in connection with the closing of the Business Combination. The distribution of our remaining non-STACK assets during the first quarter of 2018 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, the Predecessor’s assets and liabilities and operating results directly related to non-STACK assets are presented as discontinued operations within the consolidated financial statements. See Note 7 — Discontinued Operations for further discussion.(Predecessor)30In the event thatIf oil, natural gas and natural gas liquidsNGLs prices were to significantly decrease, such decreasedecreases could have a material adverse effect on our financial condition, the carrying value of our oil and natural gas properties, our proved reserves and our ability to finance operations, including the amount of our borrowing basecapacity under our senior secured revolvingthe Eighth A&R credit facility. The following table setstables set forth the average New York Mercantile Exchange (“NYMEX”) prices for oil and natural gas for the three and nine months ended March 31,September 30, 2018 and 2017:2017:63.55 62.16 62.77 62.86 51.78 11.08 21% 3.15 2.66 2.70 2.85 3.06 (0.21) Our 2018 anticipated non-acquisition capital expenditures ranges between $500 million and $580 million.We are currently utilizing eight drilling rigs as of May 2018, which will result in drilling between 170 and 180 gross wells in the STACK. Following the closing of the Business Combination, we have allocated all of our 2018 capital expenditures to develop the STACK. 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 )% natural gas liquids.NGLs. Changes in theseour derivative assets and liabilities are reported in our condensed consolidated statements of operations as gain“Gain (loss) on derivative contractscontracts”, which include both the non-cash increase andor 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 $22.6$63.1 million in the Successor Period, which includes $4.6$32.8 million in cash settlements receivedpaid for derivative contracts. The objective of our hedging program is that,to produce, over time, the combination of settlement gains and losses from derivative contracts with ordinary oil and natural gas revenues will produce relative revenue stability. However, in the short term, both settlements and fair value changes in our derivative contracts can significantly impact our results of operations, and we expect these gains and losses to continue to reflect the impact of changes in oil and natural gas prices.The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. We attempt to overcome this natural decline primarily through development of our existing undeveloped reserves, enhanced completions and well recompletions, and other enhanced recovery methods. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.primarily in Kingfisher County and Major County, Oklahoma, which is the eastern portion of the Anadarko Basin referred to as the STACK, an acronym describing both its location and the multiple, stacked pay zones present in the area.STACK. This continuously growing position is characterized by multiple productive zones located at total vertical depths between 4,000 feet and 8,000 feet. The legacy operations within our acreage are primarily shallow-decline, long-lived oil fields developed on 80-acre vertical well spacing associated with waterfloods in the Oswego, Big Lime and Manning Limestones. We continue to maintain production in these historical field pay zones. Infirst quarter ofthree months ended September 30, 2018, we brought 2853 operated horizontal wells on production of which approximately 13two were funded through our joint development agreement with BCE-STACK Development LLC (“BCE”). We had 2238 operated horizontal wells in progress as of the end of the first quarter ofSeptember 30, 2018, of which twothree were funded through our joint development agreement with BCE. As of MayNovember 1, 2018, 1816 of the 2238 operated horizontal wells in progress as of March 31,September 30, 2018 were on production. 31March 31,September 30, 2018, we had seveneight drilling rigs concurrently operating in the STACK. We currently have eightSTACK 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. 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 % 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 % 24,500 BOE/d$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 gas 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 tied to the overall decrease in natural gas commodity prices as discussed above.interest, 70%open oil, natural gas and natural gas liquids derivative contracts. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices 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 ) 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 Successor Period, 23,400 BOE/d netthree months ended September 30, 2018 (Successor) as compared to our interest, 71% oilthe three months ended September 30, 2017 (Predecessor), primarily due to an increase in capital spending and natural gas liquids, forin production in relation to current reserves. 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 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 Predecessor Period,(Successor), G&A decreased approximately $9.5 million, or 55%, as compared 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) lower costs related to non-recurring consulting fees attributable to the Contribution Agreement with SRII Opco of approximately $2.5 million incurred during the third quarter of 2017 and 19,300 BOE/d net(iii) a reduction in employee incentive compensation expense during the three months ended September 30, 2018 as compared to our interest, 70% oil and natural gas liquids, for the 2017 Predecessor Period. 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 Operations: $2.6 million, resulting from the repayment of our predecessor senior secured revolving credit facility in connection with the Business Combination, 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 our joint development agreement with BCE.March 31,September 30, 2018 (Successor) and January 1, 2018 Through February 8, 2018 (Predecessor) Compared to Threethe Nine Months Ended March 31,September 30, 2017 (Predecessor)natural gas liquidsNGLs revenues vary as a result of changes in commodity prices and production volumes. The following table provides the components of net revenue, pricesummarizes our revenues and volumeproduction data for the respective periods indicated. presented:40,278 30,972 46,940 5,210 4,276 9,591 4,714 4,000 7,072 50,202 39,248 63,603 651 494 942 2,248 1,609 3,117 223 151 275 1,249 914 1,737 12.8 12.7 10.5 44.1 41.2 34.6 4.4 3.9 3.1 24.5 23.4 19.3 61.84 62.68 49.82 (7.93) (6.44) (1.70) 53.91 56.24 48.12 2.32 2.66 3.08 0.25 0.94 (0.04) 2.57 3.60 3.04 21.18 26.41 25.70 (0.85) 21.18 26.41 24.85 Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017Net 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 % 80%81%, 79% and 74%72% of our total E&P 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 the 2018 fiscal quarter.2018. The higher average prices are tied to the overall increase of thein 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 52%approximately 50%, 54% and 54%50% of total BOE production volume forin the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.3310%9%, 11% and 15%16% of our total E&P 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 Period due to lower average prices, partially offset by an increase in production in the 2018 fiscal quarter.2018. The lower average prices are tied to the overall decrease of thein natural gas commodity prices as discussed above. Natural gas production was 30%approximately 28%, 29% and 30%33% of total BOE production volume for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively.9%10%, 10% and 11%12% of our total E&P 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 Period increased compared to the 2017 Predecessor Period due to higher average prices and an increase in production induring the 2018 fiscal quarter. The higherperiod, partially offset by lower average prices are tied to the overall increase of the oil commodity prices as discussed above. prices. Natural gas liquids production was 18%approximately 22%, 17% and 16%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 production of oil and natural gas and (ii) an amended contract, commencing in the second quarter of 2018, which allows for a greater recovery of ethane. fortotaling $5.9 million.million in the Successor Period.onin our oil, natural gas and natural gas liquids derivative contracts. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationship between contract prices and the associated forward curves.(5,165) (3,184) (1,599) 555 1,523 (138) (233) (4,610) (1,661) (1,970) (18,036) 8,959 32,212 (22,646) 7,298 30,242 Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017Gain (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 expenseexpenses for the periods indicated:8,317 4,485 11,010 5,582 3,725 5,662 1,415 953 1,266 6.66 4.91 6.34 4.47 4.08 3.26 1.13 1.04 0.73 Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017Operating 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 per BOE is $6.66 for the Successor Period $4.91 forand the 2018 Predecessor Period and $6.34 forincreased compared to the 2017 Predecessor Period.Period due to increased costs associated with salt water disposal and additional wells drilled. The increase inlease operating expense cost per BOE infor 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 increase in seasonal cost and saltwater disposal fees. Freezing weatheramended contract which allows for a greater recovery of ethane, commencing in the winter months can result in higher operating expense to prevent freezingsecond quarter of production equipment or shut-ins in Oklahoma.2018. See for the Successor Period, the 2018 Predecessor Period, and 2017 Predecessor represents throughput for our properties in the STACK primarily at the Kingfisher processing facility. The increase is primarily due to higher marketing and transportationvolumes flowing from our operated wells into the Kingfisher plant. The fee charged to provide effective gathering, efficientwe pay per unit reflects the firm processing and assurance that our production will continue to flow as the activity in the basin expandscapacity at the Kingfisher processing facility. 34and are relatedprimarily due to anthe increase in oil natural gas and natural gas liquids revenue.revenue and an increase in the severance tax rate effective in the third quarter of 2018. Exploration ExpenseWorkover expenses consists primarily of geologicalassociated with maintenance and geophysical personnel and data, lease rental expenses, expired leases, dry hole costs and settlements of asset retirement costs in excess of estimates. The following table shows the components of exploration expensesremedial efforts to increase production decreased slightly for the periods presented.Successor Period and 2018 Predecessor Period, as compared to the 2017 Predecessor Period primarily due to the timing and extent of related projects during each period.451 2,440 1,858 (45) 4,203 1,179 3,177 301 59 12 4,955 3,633 5,047 lowerhigher on a per BOE basis for the Successor Period as compared to the 2018 Predecessor Period and the 2017 Predecessor periodPeriod, primarily due to an increase in capital spending and in production in relation to current reserves. Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017Exploration 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 reserve base resulting from drilling successSuccessor Period and the 2018 Predecessor Period increased compared to the 2017 Predecessor Period, primarily due to an increase in the STACK offset by increases in the depletion base resulting from the applicationexpired leaseholds of pushdown accounting of the Business Combination.$5.2 million.10,936 11,784 18,978 8.76 12.89 10.93 Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017General 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 was$31.4 million, $24.4 million and $9.7 million for theSuccessor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Total general and administrative (“G&A”) expenses include includes non-cash charges for equityequity-based compensation of $2.8 millionawards in the Successor Period. See Note 16 — Equity BasedEquity-Based Compensation (Successor) for further detail on equity compensation.equity-based compensation awards granted during the Successor Period. No such awards were made during the Predecessor Periods. G&A expenses for the Successor Period and the 2018 Predecessor Period included $20.3$25.7 million and $16.3$17.0 million, respectively, of transaction expenses primarily attributable to the consummation of the Business Combination.2,768 28,691 24,352 9,736 31,459 24,352 9,736 Successor Predecessor February 9, 2018 Through September 30, 2018 Nine Months Ended
September 30, 2017Interest 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 following table presents information about interest expense.867 1,570 4,922 3,399 10,164 274 1,245 308 5,196 5,511 12,042 35 interest and any amounts owed during the period related tothe issuance of senior unsecured notes, borrowings under our senior secured revolvingthe Eighth A&R credit facility and capital contributions from our parent AMR.Our 2018 anticipated non-acquisition capital expenditures ranges between $500 million and $580 million. We increased our capital budget for 2018 from 2017 levels in response to the improvement in the current commodity price environment. becausesince a large percentage of our acreage is held byfor production, we have the ability to materially increase or decrease our drilling and recompletion budget in response to market conditions with decreased risk of losing significant acreage. In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves to no longer be 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.infor the remainder of 2018 predominantly with cash flows from operations, borrowings under our senior secured revolvingthe Eighth A&R credit facility and drilling and completion capital funded through our joint development agreement with BCE. As we execute our business strategy, we will continually monitor the capital resources available to meet future financial obligations and planned capital expenditures. We believe our cash flows provided by operating activities, cash on hand and availability under our senior secured revolvingthe Eighth A&R credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and to pursue our currently planned and future development drilling 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 you that operations and other needed capital will be available on acceptable terms, or at all. or the(the “senior notes”), due December 15, 2024 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. InterestThe senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017.year, beginning June 15, 2017. At any time prioryear. As described further in Note 11 of the Notes to December 15, 2019,Condensed Consolidated Financial Statements, we may, from time to time, redeem up to 35%certain amounts of the aggregate principal amount of the senior notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the 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 senior secured revolving credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes.36The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture) to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business.Under the terms of the indenture for the 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%specified amounts in relation to the principal balance of the principal amount plus accrued and unpaid interest to the date of 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.The indenture contains customary events of default, including:
redeemed.·default in any payment of interest on the senior notes when due, continued for 30 days; ·default in the payment of principal of 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 $20.0 million.March 31,September 30, 2018, we were in compliance with the indentures governing the senior notes.and in connection with the closing of the AM Contribution Agreement, we entered into the Eighth Amended and Restated senior secured revolvingA&R credit facility with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”).agent. The Eighth A&R credit facility, which will mature on February 9, 2023, is for an aggregate of $1.0 billion with an initial $350.0 million borrowing base. In April 2018, oura current borrowing base was increased toof $400.0 million until the next scheduled redetermination date in October 2018.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.May 21,September 30, 2018, we have no outstanding$80.0 million of borrowings under the Eighth A&R credit facility and have $21.9 million of outstanding letters of credit, reimbursement obligations.The principal amounts borrowed are payable onleaving a total borrowing capacity of $298.1 million available for future use.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 and one month, three months or six months period for Eurodollar loans. Eurodollar loans bear interest at a rate per annum equal to the rate at the LIBOR, plus an applicable 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 and (iii) the rate for one month’s Eurodollar loans plus 1%, plus an applicable margin ranging from 1.00% to 2.00%. The borrowing base may be reduced in connection with the next redetermination of its borrowing base. The amounts outstandingremaining amount available under the Eighth A&R credit facility are secured by first priority liens on substantially alltotaled $270.1 million reflecting borrowings for capital spending and working capital needs, net of proceeds received from the sale of the Company’s and its material operating subsidiaries’ oil and natural gas properties and associatedproduced water assets and allfrom the Company to a subsidiary of Kingfisher Midstream, LLC as described further in Note 19 of the equityNotes to Condensed Consolidated Financial Statements.Eighthfinancial ratios specified in the Eight 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 capital stock and take control of substantially all of our assets and our material operating subsidiaries that are guarantors.37The Eighth A&R credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and expenses that are general and administrative expenses 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. In addition, we can make restricted payments, so long as certain conditions are met, to any direct or indirect parent for the sole purpose of making a loan or capital contribution to Kingfisher in an amount up to $300 million until August 9, 2018.The Eighth A&R credit facility also requires us to maintain the following two financial ratios:·a current ratio, tested quarterly, commencing with the fiscal quarter ending 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 ending June 30, 2018, of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) annualized by multiplying EBITDAX for the period of (A) the fiscal quarter ending June 30, 2018 times 4, (B) the two fiscal quarter periods ending 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 times 4/4ths, of not greater than 4.0 to 1.0.At the execution of the Eighth A&R credit facility and in connection with the closing of the Business Combination, we are not subject to financial covenants ratios as of March 31, 2018. We will be required to maintain financial ratios commencing on the fiscal quarter ending June 30, 2018.The credit facility and the senior notes contain customary events of default. If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable.(used in) operating activities(used in) operating activities was $(49.3)$15.5 million, $26.5 million and $(3.9)$56.3 million for the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, respectively. Cash-based items of net income (loss) including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense providedwere approximately $0.5$88.2 million, $(2.4) million, and $23.7$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 resulted in an increase in cash of approximately $28.9 million.Working capital and other assets and liabilities resulted in a decrease of $49.8 million, and an increase of $28.9 million, for the Successor Period and the 2018 Predecessor Period respectively. The 2017 Predecessor Period working capital and other assets and liabilities had a decrease of approximately $27.6 million.Cash flow used in investing activitiesInvesting activities used cash for capital expenditures for property and equipment of approximately $129.3 million, $38.1 million and $60.6 million for the Successor Period, the 2018 Predecessor Period andDuring the 2017 Predecessor Period, respectively.$425.3$472.9 million, $16.9 million and $62.9$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 $1.0$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 periodPeriod included proceeds from the issuance of long-term debt totaling $55.1$286.1 million and capital contributions totaling $7.9$207.9 million, partially offset by repayments of long-term debt totaling $251.6 million.38Cautionary Statement Regarding Forward-Looking StatementsThe information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project”, the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our 2017 Annual Report and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.Forward-looking statements may include statements about:·the benefits of the Business Combination;·the future financial performance of the combined company following the Business Combination;·our business strategy;·our reserve quantities and the present value of our reserves;·our estimated purchase price and purchase price allocations;·our exploration and drilling prospects, inventories, projects and programs;·our horizontal drilling, completion and production technology;·our ability to replace the reserves we produce through drilling and property acquisitions;·our financial strategy, liquidity and capital required for our development program;·future oil, and natural gas prices;·the supply and demand for natural gas, natural gas liquids, crude oil and midstream services;·the timing and amount of future production of oil and natural gas;·our hedging strategy and results;·the drilling and completion of wells, including statements about future horizontal drilling plans;·competition and government regulation;·our ability to obtain permits and governmental approvals;·changes in the Oklahoma forced pooling system;·pending legal and environmental matters;·our future drilling plans;·our marketing of oil, natural gas and natural gas liquids;·our leasehold or business acquisitions;·our costs of developing our properties;·our liquidity and access to capital;·our ability to hire, train or retain qualified personnel;·general economic conditions;·operating hazards and other risks incidental to transporting, storing, gathering and processing natural gas, natural gas liquids, crude oil and midstream products;·our future operating results, including initial production values and liquid yields in our type curve areas;·the costs, terms and availability of gathering, processing, fractionation and other midstream services; and·our plans, objectives, expectations and intentions contained in this report that are not historical.39We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil, natural gas and natural gas liquids. These risks include, but are not limited to, commodity price volatility, low prices for oil, natural gas and/or natural gas liquids, global economic conditions, inflation, increased operating costs, lack of availability of drilling and production equipment, supplies, services and qualified personnel, uncertainties related to new technologies, geographical concentration of our operations, environmental risks, weather risks, security risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, reductions in cash flow, lack of access to capital, our ability to satisfy future cash obligations, restrictions in our debt agreements, the timing of development expenditures, managing our growth and integration of acquisitions, failure to realize expected value creation from property acquisitions, title defects, limited control over non-operated properties and the other risks described under “Item 1A. Risk Factors” in our 2017 Annual Report and in this report.Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. Specifically, future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.Should one or more of the risks or uncertainties described in the 2017 Annual Report or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.March 31,September 30, 2018 was a net liability of $29.3$41.5 million. A 10% increase or decrease in oil, natural gas and natural gas liquids prices with all other factors held constant would result in a decrease or increase, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity derivative contracts of approximately $29.9$27.6 million (decrease in value) or $26.7$31.2 million (increase in value), respectively, as of March 31,September 30, 2018.As of March 31, 2018, we have no outstanding balance underA 1% increase in interest rates would increase interest expense on our Eighth A&R credit facility. facility by $0.8 million, based on the balance outstanding at September 30, 2018. March 31,September 30, 2018 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.40TheSubsequent to the Business Combination, our parent company, will continueAMR, has continued to monitoranalyze, evaluate and, where appropriate, make changes in controls and procedures in a manner commensurate with the effectivenesssize, complexity and adequacyscale of its operations subsequent to the Business Combination. Other than such changes and enhancements, there have been no material changes in our internal controlscontrol over financial reporting afterduring the business combination and implement additional controls as appropriate.2018.2019 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.413.110.110.310.410.510.610.710.810.910.1031.1*4231.2*32.1*32.2*43By: By:May 21,November 14, 2018By: By:May 21,November 14, 2018By: By:44