| Supplemental Oil and Natural Gas Disclosure - Unaudited | Geographic Area of Operation All the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Texas, Louisiana, and North Dakota. However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves are presented on a consolidated basis. Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development Activities Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2018 2017 2016 (in thousands) Acquisition Costs of Properties: 1 Proved $ 13,438 $ 96,596 $ 40,242 Unproved 136,079 383,535 100,888 Exploration Costs 13,544 618 645 Development Costs 1 165,198 81,056 73,316 Total $ 328,259 $ 561,805 $ 215,091 1 See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under our farmout agreements. Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment. Oil and Natural Gas Capitalized Costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below: As of December 31, 2018 2017 (in thousands) Proved properties 1 $ 2,377,305 $ 2,258,893 Unproved properties 1,063,883 988,720 Total 3,441,188 3,247,613 Accumulated depreciation, depletion, amortization, and impairment (1,865,692 ) (1,766,842 ) Oil and natural gas properties, net $ 1,575,496 $ 1,480,771 1 Proved properties include capitalized costs related to farmout wells not yet assigned. Oil and Natural Gas Reserve Information The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2015 15,842 203,675 49,788 Revisions of previous estimates 1, 9 2,097 23,106 5,948 Purchases of minerals in place 2, 9 1,520 6,717 2,639 Extensions, discoveries and other additions 3, 9 2,589 84,339 16,646 Production (3,680 ) (47,498 ) (11,596 ) Net proved reserves at December 31, 2016 18,368 270,339 63,425 Revisions of previous estimates 1, 9 (2,298 ) 14,505 120 Purchases of minerals in place 4,9 2,335 31,323 7,555 Extensions, discoveries and other additions 5, 9 3,046 43,886 10,360 Production (3,552 ) (59,779 ) (13,515 ) Net proved reserves at December 31, 2017 17,899 300,274 67,945 Revisions of previous estimates 1 (35 ) (11,027 ) (1,873 ) Purchases of minerals in place 6 227 419 297 Extensions, discoveries and other additions 5 4,438 95,976 20,434 Production (4,962 ) (71,622 ) (16,899 ) Net proved reserves at December 31, 2018 17,567 314,020 69,904 Net Proved Developed Reserves 7 December 31, 2016 18,150 223,057 55,327 December 31, 2017 17,891 233,017 56,727 December 31, 2018 17,567 278,233 63,939 Net Proved Undeveloped Reserves 8 December 31, 2016 218 47,282 8,098 December 31, 2017 8 67,257 11,218 December 31, 2018 — 35,787 5,965 1 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells. 2 Includes the acquisition of mineral and royalty reserves primarily in the Marcellus and Wolfcamp plays. 3 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays. 4 Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian and Williston basins. 5 Includes extensions and additions related to drilling activities within multiple basins. 6 Includes the acquisition of mineral and royalty reserves primarily in the Wolfcamp play and East Texas. 7 As of December 31, 2018, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries. Proved developed reserves of 61 MBoe and 74 MBoe as of December 31, 2017 and 2016, respectively, were attributable to noncontrolling interests. 8 As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests. 9 Due to the Noble Acquisition in November 2017 and increased drilling activity on our mineral acreage in 2018, we modified our methodology for computing the sources of changes in proved reserves. The change in methodology is to classify current period production from new wells as extensions, discoveries and other additions and to classify current period production from new acquisitions as purchases of minerals in place. These items were previously classified as revisions of previous estimates. We changed the presentation of 2017 and 2016 to be consistent with our 2018 presentation. We believe the change in methodology is a more accurate reflection of the changes in our reserves although the impact to the previous years presentation was not material. Standardized Measure of Discounted Future Net Cash Flows Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion. Year Ended December 31, 2018 2017 2016 (in thousands) Future cash inflows $ 2,038,508 $ 1,643,582 $ 1,267,179 Future production costs (222,342 ) (211,064 ) (193,749 ) Future development costs (58,403 ) (70,111 ) (36,509 ) Future income tax expense (6,333 ) (2,655 ) (3,516 ) Future net cash flows (undiscounted) 1,751,430 1,359,752 1,033,405 Annual discount 10% for estimated timing (663,814 ) (497,103 ) (430,390 ) Total 1 $ 1,087,616 $ 862,649 $ 603,015 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million and $0.6 million for December 31, 2017 and 2016 attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries. The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2018 2017 2016 (in thousands) Standardized measure, beginning of year $ 862,649 $ 603,015 $ 554,972 Sales, net of production costs (475,742 ) (295,941 ) (210,354 ) Net changes in prices and production costs related to future production 1 275,091 161,221 (80,721 ) Extensions, discoveries and improved recovery, net of future production and development costs 1 370,695 166,616 139,407 Previously estimated development costs incurred during the period 14,509 11,118 28,909 Revisions of estimated future development costs 1 (558 ) 2,653 (2,380 ) Revisions of previous quantity estimates, net of related costs 1 (5,401 ) 60,476 57,577 Accretion of discount 86,441 60,512 55,662 Purchases of reserves in place, less related costs 1 8,975 113,342 42,940 Changes in timing and other 1 (49,043 ) (20,363 ) 17,003 Net increase (decrease) in standardized measures 224,967 259,634 48,043 Standardized measure, end of year $ 1,087,616 $ 862,649 $ 603,015 1 Due to the Noble Acquisition in November 2017 and increased drilling activity on our mineral acreage in 2018, we modified our methodology for computing the principal sources of changes in the standardized measure. The change in methodology is to classify current period production from new wells as extensions, discoveries and improved recovery and to classify current period production from new acquisitions as purchases of reserves in place. These items were previously classified as revisions of previous quantity estimates. We changed the presentation of 2017 and 2016 to be consistent with our 2018 presentation. We believe the change in methodology is a more accurate reflection of the principal sources of changes in the standardized measure although the impact to the previous years presentation was not material. The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. |
