| Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) | Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves. Capitalized Costs Related to Oil and Natural Gas Producing Activities The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands): December 31, 2018 2017 2016 Oil and natural gas properties Proved $ 1,269,091 $ 1,056,806 $ 840,201 Unproved 60,152 100,884 74,937 Total oil and natural gas properties 1,329,243 1,157,690 915,138 Less accumulated depreciation, depletion and impairment (580,132) (460,431) (353,030) Net oil and natural gas properties capitalized costs $ 749,111 $ 697,259 $ 562,108 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Acquisitions of properties Proved $ 30,641 $ 7,092 $ 5,142 $ 3,897 Unproved 4,197 91,139 5,491 1,899 Exploration 1,940 8,850 — 1,234 Development 158,361 187,264 27,429 149,924 Total cost incurred $ 195,139 $ 294,345 $ 38,062 $ 156,954 Results of Operations for Oil and Natural Gas Producing Activities The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the impact the Company’s operations have on actual net earnings. Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Revenues $ 348,726 $ 356,210 $ 98,307 $ 279,971 Expenses Production costs 112,173 116,372 27,640 135,715 Depreciation and depletion 127,281 118,035 36,061 90,978 Impairment — — 319,087 657,392 Total expenses 239,454 234,407 382,788 884,085 Income (loss) before income taxes 109,272 121,803 (284,481) (604,114) Income tax expense (benefit) (1) 28,520 47,722 (112,427) (229,986) Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) $ 80,752 $ 74,081 $ (172,054) $ (374,128) ____________________ 1. Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits. Oil, Natural Gas and NGL Reserve Quantities Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of mandated economic assumptions; and • the judgment of the personnel preparing the estimates. Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion. The following table represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Over 90% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2018, 2017 and 2016. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates. The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change. 2018 Activity. Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin. 2017 Activity. During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance. 2016 Activity. During 2016, on a pro forma combined basis, the Predecessor Company and Successor Company recognized total downward revisions of prior estimates of approximately 105.4 MMBoe, predominantly from revisions of approximately 94.7 MMBoe due to well performance and 12.1 MMBoe due to a decrease in commodity prices. The negative revisions from well performance were from the Mid-Continent area and resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years. Of the total performance revisions, approximately 85% were to gas and associated NGL reserves, with the revisions to gas mostly from changes made to late-life decline rates, and 15% were to oil reserves. Other decreases of reserves excluding production included the sale of WTO reserves of 24.6 MMBoe and 19.1 MMBoe of adjustment from change in accounting for Trusts. These decreases were partially offset by approximately 7.8 MMBoe of extensions due to successful drilling. The summary below presents changes in the Company’s estimated reserves. Oil NGL Natural Gas Total (MBbls) (MBbls) (MMcf)(1) MBoe Proved developed and undeveloped reserves As of December 31, 2015(2) - Predecessor 77,911 61,075 1,113,840 324,626 Adoption of ASU 2015-02 (6,971) (3,695) (50,508) (19,084) Revisions of previous estimates (39,973) (21,475) (415,568) (130,709) Extensions and discoveries 987 472 7,955 2,785 Sales of reserves in place (387) — (145,267) (24,598) Production (4,315) (3,358) (44,124) (15,027) As of October 1, 2016 - Predecessor 27,252 33,019 466,328 137,992 Revisions of previous estimates 23,978 1,139 915 25,270 Extensions and discoveries 2,868 448 10,309 5,034 Production (1,214) (999) (12,770) (4,341) As of December 31, 2016 - Successor 52,884 33,607 464,782 163,955 Revisions of previous estimates 804 2,628 44,679 10,879 Acquisitions of new reserves 18 70 683 202 Extensions and discoveries 12,446 1,914 30,080 19,373 Sales of reserves in place (204) (529) (7,055) (1,909) Production (4,157) (3,376) (44,237) (14,906) As of December 31, 2017 - Successor 61,791 34,314 488,932 177,594 Revisions of previous estimates (2,316) (8,952) (131,518) (33,188) Acquisitions of new reserves 2,146 4,131 54,436 15,350 Extensions and discoveries 11,148 2,320 35,185 19,332 Sales of reserves in place (5,273) (809) (2,969) (6,577) Production (3,477) (2,829) (36,175) (12,335) As of December 31, 2018 - Successor 64,019 28,175 407,891 160,176 Proved developed reserves As of December 31, 2015 - Predecessor 48,639 51,089 964,617 260,498 As of October 1, 2016 - Predecessor 24,541 30,238 428,050 126,121 As of December 31, 2016 - Successor 25,911 29,290 393,028 120,706 As of December 31, 2017 - Successor 25,845 29,922 407,988 123,765 As of December 31, 2018 - Successor 18,693 22,302 307,845 92,303 Proved undeveloped reserves As of December 31, 2015 - Predecessor 29,272 9,986 149,223 64,129 As of October 1, 2016 - Predecessor 2,711 2,781 38,278 11,872 As of December 31, 2016 - Successor 26,973 4,317 71,754 43,249 As of December 31, 2017 - Successor 35,946 4,392 80,944 53,829 As of December 31, 2018 - Successor 45,326 5,873 100,046 67,873 ____________________ 1. Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit. 2. Includes proved reserves attributable to noncontrolling interests as shown in the table below: Predecessor December 31, 2015 Oil (MBbl) 7,004 NGL (MBbl) 3,694 Natural gas (MMcf) 50,508 Standardized Measure of Discounted Future Net Cash Flows (Unaudited) The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, ("ASC Topic 932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows: • the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions; • pricing is applied based upon SEC prices at December 31, 2018, 2017, and 2016 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows: At December 31, 2018 2017 2016 Oil (per barrel) $ 60.86 $ 48.47 $ 38.59 NGL (per barrel) $ 25.62 $ 20.28 $ 10.99 Natural gas (per Mcf) $ 1.77 $ 1.90 $ 1.56 • future development and production costs are determined based upon actual cost at year-end; • the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and • a discount factor of 10% per year is applied annually to the future net cash flows. The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands). December 31, 2018 2017 2016 Future cash inflows from production $ 5,339,265 $ 4,621,615 $ 3,136,762 Future production costs (1,996,689) (1,837,852) (1,454,798) Future development costs(1) (1,170,113) (966,203) (665,516) Future income tax expenses (2) — (107) (142) Undiscounted future net cash flows 2,172,463 1,817,453 1,016,306 10% annual discount (1,126,860) (1,068,159) (577,942) Standardized measure of discounted future net cash flows $ 1,045,603 $ 749,294 $ 438,364 ____________________ 1. Includes abandonment costs. 2. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws , including expected tax benefits to be realized from the utilization of net operating loss carryforwards. The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands): Successor Predecessor Year Ended December 31, 2018 Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 Period from January 1, 2016 through October 1, 2016 Beginning present value $ 749,294 $ 438,364 $ 392,604 $ 1,314,562 Changes during the year Adoption of ASU 2015-02 — — — (224,965) Revenues less production (236,553) (239,838) (70,668) (144,256) Net changes in prices, production and other costs 316,095 347,458 35,684 (394,173) Development costs incurred 80,050 35,517 7,941 69,080 Net changes in future development costs (11,483) (64,484) (291,232) 436,041 Extensions and discoveries 102,961 112,556 14,986 12,449 Revisions of previous quantity estimates (91,038) 26,697 308,374 (728,254) Accretion of discount 70,576 37,226 9,375 91,337 Net change in income taxes 56 23 — 402 Purchases of reserves in-place 35,713 454 — — Sales of reserves in-place (2,029) (2,977) — (13,314) Timing differences and other(1) 31,961 58,298 31,300 (26,305) Net change for the year 296,309 310,930 45,760 (921,958) Ending present value(2) $ 1,045,603 $ 749,294 $ 438,364 $ 392,604 ____________________ 1. The change in timing differences and other are related to revisions in the Company’s estimated time of production and development. 2. Standardized Measure w as determined using SEC prices, and does not reflect actual prices received or current market prices. |
