Diamondback Energy Inc

18. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (UNAUDITED)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and amortization and accretion and impairment. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates and their associated future net cash flows were prepared by the Company’s internal reservoir engineers and audited by Ryder Scott, independent petroleum engineers, as of December 31, 2023 and 2022 and prepared by Ryder Scott as of December 31, 2021. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon SEC Prices for the periods ending December 31, 2023, 2022 and 2021, respectively. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the net revenue interest in the Company’s properties, all of which are located within the continental United States. Although the Company believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The following table presents changes in the Company’s estimated proved reserves (including those attributable to Viper). As of December 31, 2023, none of the Company’s total proved reserves were classified as proved developed non-producing.

(1) Includes total proved reserves of 78,870 MBOE,65,516 MBOE,58,828 MBOE and 41,745 MBOE as of December 31, 2023, 2022, 2021 and 2020, respectively, attributable to a non-controlling interest in Viper.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2023, the Company’s extensions and discoveries of 355,874 MBOE resulted primarily from the drilling of 954 new wells in which the Company has an interest, including 826 wells in which the Company owns only a mineral interest through Viper, and from 344 new proved undeveloped locations added. Viper royalty interests accounted for 7% of the extension volumes. The Company’s downward revisions of previous estimates of 54,470 MBOE were primarily attributable to negative revisions of (i)62,370 MBOE associated with lower commodity prices and (ii)32,249 MBOE due to PUD downgrades related to changes in the corporate development plan. These were partially offset by positive revisions of 40,149 MBOE due to improved performance. Purchases of 70,481 MBOE consisted of 54,470 MBOE attributable largely to the Lario Acquisition and 16,011 MBOE of Viper royalty purchases. Divestitures of 63,682 MBOE related primarily to non-core Midland Basin assets.

During the year ended December 31, 2022, the Company’s extensions and discoveries of 334,495 MBOE resulted primarily from the drilling of 654 new wells in which the Company has a working interest, including 576 wells in which we own only a mineral interest through Viper, and from 311 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,784 MBOE were the result of negative revisions of 98,902 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the FireBird Acquisition, partially offset with positive revisions of 92,118 MBOE associated with higher commodity prices. Purchases of 68,043 MBOE consisted of 67,037 MBOE attributable largely to the FireBird Acquisition and 1,005 MBOE of Viper royalty purchases. Divestitures of 10,882 MBOE related primarily to non-core Delaware Basin assets and the Eagle Ford Basin Divestiture.

During the year ended December 31, 2021, the Company’s extensions and discoveries of 518,722 MBOE resulted primarily from the drilling of 470 new wells in which the Company has a working interest, including 345 wells in which we own only a mineral interest through Viper, and from 439 new proved undeveloped locations added. Viper royalty interests accounted for 6% of the extension volumes. The Company’s downward revisions of previous estimates of 134,705 MBOE were the result of negative revisions of 268,560 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 133,855 MBOE associated with higher commodity prices and improved well performance. Purchases of 285,309 MBOE primarily resulted from 276,207 MBOE attributable largely to the QEP Merger and Guidon Acquisition, and 9,102 MBOE of Viper royalty purchases, including the Swallowtail Acquisition. Divestitures of 59,775 MBOE related primarily to the Williston Basin Divestiture.

Proved Undeveloped Reserves (PUDs)

At December 31, 2023, the Company’s estimated PUD reserves were approximately 681,231 MBOE, a 51,813 MBOE increase over the reserve estimate at December 31, 2022 of 629,418 MBOE. The following table includes the changes in PUD reserves for 2023 (MBOE):

The increase in proved undeveloped reserves was primarily attributable to extensions of 266,178 MBOE from 344 gross (295 net) wells in which the Company has a working interest and 10,097 MBOE from 179 gross wells in which Viper owns royalty interests. Of the 344 gross working interest wells,321 were in the Midland Basin and 23 were in the Delaware Basin. Transfers of 187,097 MBOE from undeveloped to developed reserves were the result of drilling or participating in 204 gross (184 net) horizontal wells in which the Company has a working interest and 170 gross wells in which the Company also has a royalty interest or mineral interest through Viper. Downward revisions of 34,110 MBOE were primarily the result of negative revisions of 25,893 MBOE due to downgrades related to changes in the corporate development plan, and negative revisions of 8,217 MBOE attributable to lower commodity prices. Purchases of 4,206 MBOE consisted of 3,288 MBOE primarily from insignificant trades and acquisitions and 918 MBOE from the GRP Acquisition and other insignificant royalty interest purchases.

During 2023, approximately $2.0 billion in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Estimated future development costs relating to the development of PUDs are projected to be approximately $1.6 billion in 2024, $1.4 billion in 2025, $930 million in 2026 and $676 million in 2027. Since our formation in 2011, our average drilling costs and drilling times have been reduced, and we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

With our current development plan, we expect to continue our strong PUD conversion ratio in 2024 by converting an estimated 38% of our PUDs to a proved developed category and developing approximately 83% of the consolidated 2023 year-end PUD reserves by the end of 2026. As of December 31, 2023, all of our proved undeveloped reserves are scheduled to be developed within five years from the date they were initially recorded.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on the unweighted arithmetic average, first-day-of-the-month price for the rolling 12-month period. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2023, 2022 and 2021:

(1) Includes approximately $685 million, $756 million, and $339 million of undiscounted future asset retirement costs for the years ended December 31, 2023, 2022 and 2021, respectively, based on estimates made at the end of each of the respective years,

(2) Includes $3.2 billion, $3.5 billion and $2.1 billion, for the years ended December 31, 2023, 2022 and 2021, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 44%,44% and 46% non-controlling interest at December 31, 2023 2022 and 2021, respectively.

The table below presents the SEC Prices as adjusted for differentials and contractual arrangements utilized in the computation of future cash inflows:

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: