16. 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 capitalized costs for the years ended December 31, 2015 and 2014 (in thousands):


	December 31,
	2015		2014
Capitalized costs at the end of the period:⁽ᵃ⁾
Oil and natural gas properties and related equipment (successful efforts method)
Property costs
Proved property	$	731,548	$	649,432
Unproved property		39		1,560
Land		501		501
Total property costs		732,088		651,493
Materials and supplies		1,056		1,056
Total		733,144		652,549
Less: Accumulated depreciation, depletion, amortization and impairments		(652,167)		(517,239)
Oil and natural gas properties and equipment, net	$	80,977	$	135,310

(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, 2015 and 2014 (in thousands):


	For the Year Ended December 31,
	2015		2014
Costs incurred for the period:
Acquisition of properties
Proved	$	81,378	$	1,239
Unproved		—		112
Development costs		468		5,865
Oil and natural gas properties and equipment, net	$	81,846	$	7,216

The development costs for the years ended December 31, 2015 and 2014 primarily represent costs to develop our proved undeveloped reserves. The properties acquired in 2015 and 2014 were in Texas and Louisiana.

We had no exploration and dry hole costs in 2015 and 2014, 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 operations are oil and natural gas producing activities 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, 2013	15,209	2,072	12,994	143
Extensions and discoveries	509	416	93	—
Puchase of reserves in place	72	72	—	—
Revisions of previous estimates	2,361	(590)	3,008	(57)
Production	(1,524)	(308)	(1,188)	(28)
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

Proved developed reserves:
December 31, 2014	12,439	1,523	10,858	58
December 31, 2015	11,523	3,071	7,705	747

Proved undeveloped reserves:
December 31, 2014	4,188	139	4,049	—
December 31, 2015	119	88	31	—

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, 2015 and 2014, proved reserve estimates were 11.6 MMBoe and 16.6 MMBoe, respectively. For 2015, NSAI and Ryder Scott, independent petroleum engineering firms, prepared the estimates of our proved reserves which were used to prepare our financial statements. For 2014, NSAI prepared the estimates of our proved reserves which were used to prepare our financial statements.

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: $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.

Our 2014 estimates of total proved reserves increased 1.4 MMBoe from 2013 due to a 2.2 MMBoe increase in undeveloped gas reserves in the Cherokee Basin. The higher volumes were due to a higher gas price. Our reserves are 90% 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: $93.95 per barrel for oil, $35.11 per barrel for NGLs and $4.09 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 Year Ended December 31,
	2015		2014
Future cash inflows	$	289,767	$	532,152
Future production costs		(165,861)		(260,909)
Future estimated development costs		(19,026)		(57,741)
Future net cash flows		104,880		213,502
10% annual discount for estimated timing of cash flows		(37,028)		(93,969)
Standardized measure of discounted estimated future net cash flows related to proved gas reserves	$	67,852	$	119,533

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


	For the Year Ended December 31,
	2015		2014
Beginning of the period	$	119,533	$	143,714
Sales and transfers of oil and natural gas, net of production costs		(30,748)		(38,817)
Net changes in prices and production costs related to future production		(125,979)		(18,410)
Development costs incurred during the period		5,016		18,075
Changes in extensions and discoveries		178		24,611
Revisions of previous quantity estimates		(11,299)		(22,034)
Purchases and sales of reserves in place		109,181		1,918
Accretion discount		11,953		14,371
Other		(9,983)		(3,895)
Standardized measure of discounted future net cash flows related to proved gas reserves	$	67,852	$	119,533