20. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)

The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.

Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.

Costs

The following table sets forth our capitalized costs as of December 31, 2019 and 2018 (in thousands):


	December 31,
	2019		2018
Capitalized costs at the end of the period:⁽ᵃ⁾
Oil and natural gas properties and related equipment (successful efforts method)
Proved property	$	112,476	$	112,173
Less: Accumulated depreciation, depletion, amortization and impairments		(69,541)		(65,647)
Oil and natural gas properties and equipment, net	$	42,935	$	46,526

(a)

Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2019 and 2018 (in thousands):


	Years Ended December 31,
	2019		2018
Costs incurred for the period:
Acquisition of properties
Proved	$	—	$	—
Development costs		131		11
Oil and natural gas properties and equipment, net	$	131	$	11

The development costs for the years ended December 31, 2019 and 2018 primarily represent costs related to recompletions.

We had no exploration and dry hole costs in 2019 and 2018.

Results of Operations

The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our oil and natural gas producing activities are located in the United States.

Net Proved Reserves of Natural Gas, NGLs and Oil

The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.


				Natural Gas
	Total	Oil	Natural Gas	Liquids
	(MMBoe)	(in MMBoe)	(in MMBoe)	(in MMBoe)
Net proved reserves
December 31, 2017	5,265	3,246	1,109	910
Sales of reserves in place	(1,105)	(272)	(322)	(511)
Revisions of previous estimates	(268)	(199)	(261)	192
Production	(439)	(296)	(72)	(71)
December 31, 2018	3,453	2,479	454	520
Sales of reserves in place	—	—	—	—
Revisions of previous estimates	(145)	(10)	(67)	(68)
Production	(309)	(228)	(39)	(42)
December 31, 2019	2,999	2,241	348	410

Proved developed reserves:
December 31, 2018	3,453	2,479	454	520
December 31, 2019	2,999	2,241	348	410

Reserves and Related Estimates

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.

Our year end December 31, 2019 and 2018, proved reserve estimates were 3.0 MMBoe and 3.5 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements.

Our 2019 estimates of total proved reserves decreased 0.5 MMBoe from 2018 due to production of 0.3 MMBoe and revisions of previous estimates of 0.2 MMBoe. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $59.55 per Bbl for oil, $13.68 per Bbl for NGLs and $2.66 per Mcf for natural gas.

Our 2018 estimates of total proved reserves decreased 1.8 MMBoe from 2017 primarily due to a decrease in reserves of 1.1 MMBoe due to the Louisiana Divestiture, Briggs Divestiture and Cola Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $66.95 per Bbl for oil, $23.00 per Bbl for NGLs and $3.21 per Mcf for natural gas.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, Including a Reconciliation of Changes Therein

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.

Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity.

The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands):


	Years Ended December 31,
	2019		2018
Future cash inflows	$	144,628	$	186,675
Future production costs		(80,007)		(99,187)
Future estimated development costs		(3,400)		(4,043)
Future net cash flows		61,221		83,445
10% annual discount for estimated timing of cash flows		(22,871)		(31,199)
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves	$	38,350	$	52,246

The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands):


	Years Ended December 31,
	2019		2018
Beginning of the period	$	52,246	$	56,697
Sales and transfers of oil and natural gas, net of production costs		(8,006)		(14,795)
Net changes in prices and production costs related to future production		(7,330)		17,392
Changes in development costs		35		207
Revisions of previous quantity estimates		(1,942)		(4,203)
Purchases and sales of reserves in place		—		(5,423)
Accretion discount		5,225		5,670
Change in production rates, timing, and other		(1,878)		(3,299)
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	$	38,350	$	52,246