Note 17. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

	Years Ended December 31,
	2016			2015			2014
	(In thousands)
Evaluated oil and natural gas properties	$	3,115,012		$	3,616,325		$	3,329,338
Support equipment and facilities		199,093			205,876			198,088
Accumulated depletion, depreciation, and amortization		(1,743,274	)		(1,878,549	)		(1,060,114	)
Total	$	1,570,831		$	1,943,652		$	2,467,312

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

	Years Ended December 31,
	2016		2015		2014
	(In thousands)
Property acquisition costs, proved	$	—	$	77,834	$	983,076
Property acquisition costs, unproved		—		1,887		720
Exploration		792		2,078		—
Development		54,310		233,241		308,724
Total	$	55,102	$	315,040	$	1,292,520

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We engaged Ryder Scott to audit our reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2016. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

	2016		2015		2014
Oil ($/Bbl):
WTI (1)	$	42.75	$	46.79	$	91.48

NGL ($/Bbl):
WTI (1)	$	42.75	$	46.79	$	91.48

Natural Gas ($/MMbtu):
Henry Hub (2)	$	2.48	$	2.58	$	4.35

(1)

The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential.

(2)

The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves as of December 31, 2016, 2015 and 2014, respectively:

	Year Ended December 31, 2016
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		90,945			461,526			43,395			1,267,571
Extensions and discoveries		297			288			42			2,320
Production		(3,883	)		(44,776	)		(2,283	)		(81,773	)
Sale of minerals in place		(3,228	)		(15,227	)		(123	)		(35,328	)
Revision of previous estimates		(18,390	)		(30,795	)		(15,847	)		(236,225	)
End of year		65,741			371,016			25,184			916,565

Proved developed reserves:
Beginning of year		50,817			311,147			30,315			797,936
End of year		45,536			280,035			18,923			666,786

Proved undeveloped reserves:
Beginning of year		40,128			150,379			13,080			469,635
End of year		20,205			90,981			6,261			249,779

	Year Ended December 31, 2015
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		100,258			727,216			59,034			1,682,960
Extensions and discoveries		2,319			8,686			558			25,950
Purchase of minerals in place		10,132			34,128			367			97,122
Production		(4,087	)		(50,875	)		(2,820	)		(92,315	)
Sale of minerals in place		(380	)		(13,731	)		(758	)		(20,559	)
Revision of previous estimates		(17,297	)		(243,898	)		(12,986	)		(425,587	)
End of year		90,945			461,526			43,395			1,267,571

Proved developed reserves:
Beginning of year		54,723			417,247			37,260			969,141
End of year		50,817			311,147			30,315			797,936

Proved undeveloped reserves:
Beginning of year		45,535			309,969			21,774			713,819
End of year		40,128			150,379			13,080			469,635

	Year Ended December 31, 2014
	Oil			Gas			NGLs			Equivalent
	(MBbls)			(MMcf)			(MBbls)			(MMcfe)
Proved developed and undeveloped reserves:
Beginning of year		39,635			737,908			35,794			1,190,484
Extensions and discoveries		849			12,783			711			22,145
Purchase of minerals in place		69,095			13,036			22,351			561,713
Production		(3,135	)		(48,721	)		(2,498	)		(82,520	)
Revision of previous estimates		(6,186	)		12,210			2,676			(8,862	)
End of year		100,258			727,216			59,034			1,682,960

Proved developed reserves:
Beginning of year		22,429			427,983			17,637			668,381
End of year		54,723			417,247			37,260			969,141

Proved undeveloped reserves:
Beginning of year		17,206			309,925			18,157			522,103
End of year		45,535			309,969			21,774			713,819

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

•

The 351.0 Bcfe reduction in reserves for the year ended December 31, 2016 is primarily due to a 148.3 Bcfe downward pricing revision and a 87.9 Bcfe downward revision due to updated well performance data. We divested 35.3 Bcfe during the year ended December 31, 2016. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2016.

•

The 415.4 Bcfe reduction in reserves for the year ended December 31, 2015 is primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. We acquired 97.1 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 58.5 Bcfe. Proved undeveloped reserves decreased primarily due to downward pricing during the year ended December 31, 2015.

•

We acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. We also acquired 45.0 Bcfe from the Eagle Ford Acquisition. An upward revision of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on certain East Texas properties. The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain other East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition.

See Note 4 for additional information on acquisitions and divestitures.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:

	Years Ended December 31,
	2016			2015			2014
	(In thousands)
Future cash inflows	$	3,666,731		$	5,952,935		$	14,190,450
Future production costs		(2,384,195	)		(3,194,577	)		(4,821,051	)
Future development costs		(440,496	)		(808,512	)		(1,455,926	)
Future income tax expense (1)		—			—			(119,675	)
Future net cash flows for estimated timing of cash flows		842,040			1,949,846			7,793,798
10% annual discount for estimated timing of cash flows		(446,199	)		(1,360,292	)		(4,881,811	)
Standardized measure of discounted future net cash flows	$	395,841		$	589,554		$	2,911,987

(1)

We are subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2016, 2015 and 2014. The 2014 amount was related to Classic since its reserves were a part of a taxable entity for federal income tax purposes for the year ended December 31, 2014.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2016:

	Years Ended December 31,
	2016			2015			2014
	(In thousands)
Beginning of year	$	589,554		$	2,911,987		$	1,718,204
Sale of oil and natural gas produced, net of production costs		(107,357	)		(128,382	)		(354,932	)
Purchase of minerals in place		—			75,998			1,489,477
Sale of minerals in place		(28,277	)		(45,100	)		—
Extensions and discoveries		2,016			18,582			44,843
Changes in income taxes, net		—			63,180			(63,180	)
Changes in prices and costs		(404,870	)		(2,764,481	)		(170,682	)
Previously estimated development costs incurred		89,748			322,446			275,078
Net changes in future development costs		254,043			448,089			(133,098	)
Revisions of previous quantities		14,414			(344,775	)		(48,087	)
Accretion of discount		58,956			297,517			171,820
Change in production rates and other		(72,386	)		(265,507	)		(17,456	)
End of year	$	395,841		$	589,554		$	2,911,987