19. 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, 2016 and 2015 (in thousands):


	December 31,
	2016		2015
Capitalized costs at the end of the period:⁽ᵃ⁾
Oil and natural gas properties and related equipment (successful efforts method)
Property costs
Proved property	$	758,366	$	731,548
Unproved property		46		39
Land		501		501
Total property costs		758,913		732,088
Materials and supplies		1,056		1,056
Total		759,969		733,144
Less: Accumulated depreciation, depletion, amortization and impairments		(674,338)		(652,167)
Oil and natural gas properties and equipment, net	$	85,631	$	80,977

(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, 2016 and 2015 (in thousands):


	For the Years Ended December 31,
	2016		2015
Costs incurred for the period:
Acquisition of properties
Proved	$	25,622	$	81,378
Unproved		—		—
Development costs		937		2,005
Oil and natural gas properties and equipment, net	$	26,559	$	83,383

The development costs for the year ended December 31, 2016 primarily represents costs related to recompletions, while those for the same period in 2015 related to the development of our proved undeveloped reserves. The properties acquired in 2016 were in Texas, and the properties acquired in 2015 were in Texas and Louisiana.

We had no exploration and dry hole costs in 2016 and 2015, with the exception of impairments related to unproved properties which were recorded as exploration costs.

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 Oil, Natural Gas and Natural Gas Liquids Reserves

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, 2014	16,627	1,662	14,907	58
Extensions and discoveries	3	3	—	—
Puchase of reserves in place	5,124	3,516	799	809
Revisions of previous estimates	(9,038)	(1,754)	(7,175)	(109)
Production	(1,074)	(268)	(795)	(11)
December 31, 2015	11,642	3,159	7,736	747
Purchase of reserves in place	1,397	1,049	176	172
Sales of reserves in place	(610)	(47)	(563)	—
Revisions of previous estimates	(4,426)	(316)	(4,202)	92
Production	(1,133)	(331)	(721)	(81)
December 31, 2016	6,870	3,514	2,426	930

Proved developed reserves:
December 31, 2015	11,523	3,071	7,705	747
December 31, 2016	6,870	3,514	2,426	930

Proved undeveloped reserves:
December 31, 2015	119	88	31	—
December 31, 2016	—	—	—	—

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 December 31, 2016 and 2015, proved reserve estimates were 6.9 MMBoe and 11.6 MMBoe, respectively. For the year ended December 31, 2016, Ryder Scott, an independent petroleum engineering firm, prepared the estimates of our proved reserves which were used to prepare our financial statements. For the year ended December 31, 2015, NSAI, an independent petroleum engineering firm, and Ryder Scott prepared the estimates of our proved reserves which were used to prepare our financial statements.

Our 2016 estimates of total proved reserves decreased 4.7 MMBoe from 2015 due to a downward revision of previous estimates of 4.4 MMBoe offset by an increase of 1.4 MMBoe related to the purchase of reserves in place. The downward revision was due to lower commodity prices as well as a decrease in proved developed not producing and PUD reserves, partially offset by an increase in PDP reserves from our Production Acquisition. Our reserves are 35% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $38.85 per barrel for oil, $13.84 per barrel for NGLs and $2.28 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline and our sale of reserves in place.

Our 2015 estimates of total proved reserves decreased 5.0 MMBoe from 2014 due to a 4.0 MMBoe decrease in undeveloped gas reserves. The lower volumes were due to a higher gas price. Our reserves are 66% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $50.28 per barrel for oil, $19.90 per barrel for NGLs and $2.58 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved 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):


	For the Years Ended December 31,
	2016		2015
Future cash inflows	$	182,612	$	289,767
Future production costs		(102,569)		(165,861)
Future estimated development costs		(8,872)		(19,026)
Future net cash flows		71,171		104,880
10% annual discount for estimated timing of cash flows		(21,535)		(37,028)
Standardized measure of discounted estimated future net cash flows related to proved gas reserves	$	49,636	$	67,852

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


	For the Years Ended December 31,
	2016		2015
Beginning of the period	$	67,852	$	119,533
Sales and transfers of oil and natural gas, net of production costs		(8,700)		(30,748)
Net changes in prices and production costs related to future production		(7,868)		(125,979)
Changes in development costs		5,040		5,016
Changes in extensions and discoveries		—		178
Revisions of previous quantity estimates		(17,924)		(11,299)
Purchases and sales of reserves in place		9,134		109,181
Accretion discount		6,175		11,953
Change in production rates, timing, and other		(4,073)		(9,983)
Standardized measure of discounted future net cash flows related to proved gas reserves	$	49,636	$	67,852