Supplemental Oil And Natural Gas Disclosures | NOTE 24 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited) During January 2019, we finalized our development plan for the next five years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have continuing access to that capital source in the event of a failure of the leverage covenant. Thus, we concluded that we did not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved. The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. The information presented during the Predecessor Periods includes amounts related to discontinued operations. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Under our gathering contract with KFM, we have options regarding how we accept or reject ethane volumes. Our reserve disclosures that follow assume that we recover (rather than reject) ethane volumes, which generally has the effect of increasing the reserves, with no corresponding increase to value or future cash flow. Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Oil and gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. Estimated Quantities of Proved Reserves The following table sets forth our net proved reserves as of the Successor Period, the 2018 Predecessor Period, the years ended December 31, 2017 and 2016 , and the changes therein during the periods then ended. Proved oil and gas reserves are the estimated quantities of crude oil, gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the dates the estimates were made). Oil (Mbbls) Gas (MMcf) NGL’s (Mbbls) Boe (Mbbls) Total Proved Reserves: Balance at December 31, 2015 (Predecessor) 34,142 155,423 18,437 78,483 Production (4,001 ) (13,959 ) (956 ) (7,284 ) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73 ) (966 ) (10 ) (244 ) Revisions of previous quantity estimates and other (3,680 ) 14,100 (3,794 ) (5,124 ) Balance at December 31, 2016 (Predecessor) 57,799 316,005 28,290 138,757 Production (4,850 ) (18,218 ) (1,387 ) (9,274 ) Purchases in place 725 4,860 401 1,936 Discoveries and extensions 20,135 108,676 9,640 47,888 Sales of reserves in place (3,622 ) (1,280 ) — (3,836 ) Revisions of previous quantity estimates and other 3,331 23,476 (57 ) 7,187 Balance at December 31, 2017 (Predecessor) 73,518 433,519 36,887 182,658 Production (521 ) (1,984 ) (161 ) (1,012 ) Purchases in place — — — — Discoveries and extensions — — — — Sales of reserves in place (2) (1,667 ) (24,239 ) (771 ) (6,478 ) Revisions of previous quantity estimates and other 375 3,506 289 1,248 Balance at February 8, 2018 (Predecessor) 71,705 410,802 36,244 176,416 Production (5,053 ) (16,913 ) (2,268 ) (10,140 ) Purchases in place (3) 2,658 13,331 1,751 6,631 Discoveries and extensions (3) 30,026 155,306 19,646 75,557 Sales of reserves in place — — — — Revisions of previous quantity estimates and other (3)(4) (74,064 ) (418,378 ) (35,581 ) (179,375 ) Balance at December 31, 2018 (Successor) 25,272 144,148 19,792 69,089 Proved Developed Reserves: Balance at December 31, 2015 14,942 71,752 6,958 33,859 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Balance at December 31, 2017 20,347 150,183 12,180 57,557 Balance at February 8, 2018 19,345 126,231 11,348 51,731 Balance at December 31, 2018 25,272 144,148 19,792 69,089 Proved Undeveloped Reserves: Balance at December 31, 2015 19,200 83,671 11,479 44,624 Balance at December 31, 2016 40,967 222,644 20,313 98,386 Balance at December 31, 2017 53,171 283,336 24,707 125,101 Balance at February 8, 2018 52,360 284,571 24,896 124,685 Balance at December 31, 2018 — — — — _________________ (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from HMI. (2) Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to the AM contributor and are classified as discontinued operations in our consolidated financial statements. (3) Effective as of December 31, 2018 , due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we have removed all of our PUDs from our total estimated proved reserves. Discoveries and extensions and purchases in place during the 2018 Successor Period include approximately 47,092 MBoe in PUDs, and this amount is also included with our negative revisions and is consequently removed from our total proved reserves at December 31, 2018 . (4) In addition to removing PUDs, we lowered our estimate of proved reserves at December 31, 2018 by approximately 101,516 MBoe, largely due to results of the 2018 drilling program demonstrating lower estimated recovery per 640 -acre section. Partially offsetting this was an increase in recoverable reserves of approximately 11,196 MBoe, due mainly to higher average commodity prices in 2018 as compared to 2017. Results of Operations for Oil and Gas Producing Activities Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Operating revenue $ 414,507 $ 40,136 $ 269,386 $ 142,356 Production expense (1) 247,748 30,743 138,833 87,869 Depreciation, depletion and amortization 133,554 11,670 89,115 53,755 Exploration expense 34,085 7,003 13,563 17,230 Impairment expense 2,033,712 — 1,188 382 Income tax expense (benefit) 4 — 6 — Results of operations $ (2,034,596 ) $ (9,280 ) $ 26,681 $ (16,880 ) ________________ (1) Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and general and administrative expense. Capitalized Costs Relating to Oil and Gas Producing Activities December 31, (in thousands) Successor 2018 Predecessor 2017 (1) Capitalized costs: Proved properties $ 2,110,346 $ 1,545,963 Unproved properties 816,282 116,787 Total 2,926,628 1,662,750 Accumulated depreciation, depletion, amortization and impairment (2,163,291 ) (711,275 ) Net capitalized costs $ 763,337 $ 951,475 _________________ (1) Includes amounts related to non-STACK assets distributed in the 2018 Predecessor Period and reflected as discontinued operations. Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities Acquisition costs in the table below include costs incurred to purchase, lease or otherwise acquire property. Exploration expenses include additions to exploratory wells and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment. Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Costs incurred during the period: (1) Property acquisition Unproved (2) $ 54,587 $ 4,240 $ 88,378 $ 66,788 Proved (3) 16,300 327 11,704 68,478 Exploration 32,130 3,678 26,836 28,480 Development (4) 664,138 37,672 351,570 165,796 $ 767,155 45,917 $ 478,488 $ 329,542 _________________ (1) Costs incurred in all Predecessor Periods include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. Costs incurred in 2017 include amounts related to the Weeks Island field and other assets, all of which are classified as discontinued operations. (2) Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million and $45.6 million for the 2018 Successor Period and the year ended December 31, 2017, respectively. (3) Property acquisition costs for proved properties in 2016 include the transfer of Contributed Wells by our former Class B partner to us of $65.7 million . (4) Includes asset retirement additions (revisions) of $5.6 million , $4.4 million , and $1.9 million for the Successor Period, and years ended December 31, 2017 and 2016 , respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions). Standardized Measure of Discounted Future Net Cash Flows The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the Successor Period, the 2018 Predecessor Period, and for the years ended December 31, 2017 and 2016 . Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. The following table sets forth the components of the standardized measure of discounted future net cash flows: Successor Predecessor (in thousands, except per unit data) December 31, 2018 February 8, 2018 December 31, 2017 December 31, 2016 Future cash inflows $ 2,446,888 $ 5,798,886 $ 5,799,753 $ 3,547,130 Future production costs (1,214,479 ) (2,556,361 ) (2,617,476 ) (1,811,683 ) Future development costs (23,183 ) (965,780 ) (1,035,481 ) (709,738 ) Future income taxes — — — — Future net cash flows (1) 1,209,226 2,276,745 2,146,796 1,025,709 Discount to present value at 10 percent per annum (396,375 ) (1,096,859 ) (1,040,874 ) (467,101 ) Standardized measure of discounted future net cash flows $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 Base price for crude oil, per barrel, in the above computation $ 65.56 $ 52.89 $ 51.34 $ 42.75 Base price for natural gas, per MMBtu, in the above computation $ 3.10 $ 2.99 $ 2.98 $ 2.49 Realized price for NGLs, per barrel, in the above computation $ 22.44 $ 27.48 $ 26.06 $ 15.18 Changes in Standardized Measure of Discounted Future Net Cash Flows Successor Predecessor (in thousands) February 9, 2018 Through December 31, 2018 January 1, 2018 Through February 8, 2018 Year Ended December 31, 2017 Year Ended December 31, 2016 Balance at beginning of period $ 1,179,886 $ 1,105,922 $ 558,608 $ 629,596 Sales and transfers of oil and gas produced, net of production costs (278,091 ) (30,391 ) (202,232 ) (124,610 ) Net changes in prices and production costs 38,963 71,334 354,900 (324,638 ) Revisions of previous quantity estimates (1) (1,120,097 ) 10,887 (12,106 ) (35,972 ) Purchases of reserves in-place 24,376 — 11,483 40,611 Sales of reserves in-place (2) — (4,807 ) (20,423 ) 2,345 Current year discoveries and extensions, less related costs 684,700 — 513,012 356,631 Changes in estimated future development costs (39,069 ) 491 (5,869 ) 849 Development costs incurred during the period 160,583 — 26,317 8,363 Accretion of discount 117,989 110,592 55,861 62,960 Net change in income taxes — — — — Change in production rate (timing) and other 43,611 (84,142 ) (173,629 ) (57,527 ) Net change (367,035 ) 73,964 547,314 (70,988 ) Balance at end of period $ 812,851 $ 1,179,886 $ 1,105,922 $ 558,608 _________________ (1) Our revisions include approximately $250.0 million of proved undeveloped reserves that were removed at December 31, 2018 due to our subsequent determination of substantial doubt about our ability to continue as a going-concern and the impact on our ability to fund the costs associated with developing those reserves. (2) The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties, and in 2017 the sale of Weeks Island Field and other assets, all of which are reflected as discontinued operations in the Company’s consolidated financial statements. |