Supplemental Oil and Gas Disclosures (Unaudited)

The following unaudited information regarding our oil and gas reserves has been prepared and is presented pursuant to requirements of the Securities and Exchange Commission (SEC) and the Financial Accounting Standards Board (FASB).

As of year-end 2016, we have divested substantially all of our oil and gas working interest properties. As a result of this significant change in our operations, we have reported the results of operations and financial position of these assets as discontinued operations within our consolidated statements of income (loss) and comprehensive income (loss) and consolidated balance sheets for all periods presented. However, all information presented in this unaudited supplemental oil and gas disclosures footnote includes all oil and gas reserve estimates and results of operations.

We lease our mineral interests, principally in Texas and Louisiana, to third-party entities for the exploration and production of oil and gas. When we lease our mineral interests, we may negotiate a lease bonus payment and we retain a royalty interest and may take an additional participation in production, including a working interest in which we pay a share of the costs to drill, complete and operate a well and receive a proportionate share of the production revenues.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to assist in preparing estimates of our proved oil and gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2016, 2015 and 2014.

These estimates were based on the economic and operating conditions existing at year-end 2016, 2015 and 2014. Proved developed reserves are those quantities of petroleum from existing wells and facilities, which by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward for known reservoirs and under defined economic conditions, operating methods and government regulations.

SEC rules require disclosure of proved reserves using the twelve-month average beginning-of-month price (which we refer to as the average price) for the year. These same average prices also are used in calculating the amount of (and changes in) future net cash inflows related to the standardized measure of discounted future net cash flows.

For 2016, 2015 and 2014, the average spot price per barrel of oil based on the West Texas Intermediate price is $42.75, $50.28 and $94.99 and the average price per MMBTU of gas based on the Henry Hub spot is $2.48, $2.59 and $4.35. All prices were then adjusted for quality, transportation fees and differentials.

The process of estimating proved reserves and future net cash flows is complex involving decisions and assumptions in evaluating the available engineering and geologic data and prices for oil and gas and the cost to produce these reserves and other factors, many of which are beyond our control. As a result, these estimates are imprecise and should be expected to change as future information becomes available. These changes could be significant. In addition, this information should not be construed as being the current fair market value of our proved reserves.

Estimated Quantities of Proved Oil and Gas Reserves

Estimated quantities of proved oil and gas reserves are summarized as follows:



	Reserves
	Oil ^(a) (Barrels)		Gas (Mcf)
	(In thousands)
Consolidated entities:
Year-end 2013	5,824		13,630
Revisions of previous estimates	608		293
Extensions and discoveries	2,191		774
Acquisitions	85		31
Sales	(105	)	(218	)
Production	(931	)	(1,861	)
Year-end 2014	7,672		12,649
Revisions of previous estimates	(855	)	(1,675	)
Extensions and discoveries	224		173
Acquisitions	—		—
Sales	(704	)	(1,223	)
Production	(1,158	)	(1,967	)
Year-end 2015	5,179		7,957
Revisions of previous estimates	(11	)	631
Extensions and discoveries	29		—
Acquisitions	—		—
Sales	(4,460	)	(3,756	)
Production	(291	)	(996	)
Year-end 2016	446		3,836
Our share of ventures accounted for using the equity method:
Year-end 2013	—		2,332
Revisions of previous estimates	—		(382	)
Production	—		(199	)
Year-end 2014	—		1,751
Revisions of previous estimates	—		(320	)
Production	—		(168	)
Year-end 2015	—		1,263
Revisions of previous estimates	—		79
Production	—		(143	)
Year-end 2016	—		1,199
Total consolidated and our share of equity method ventures:
Year-end 2014
Proved developed reserves	5,269		12,599
Proved undeveloped reserves	2,403		1,801
Total Year-end 2014	7,672		14,400
Year-end 2015
Proved developed reserves	5,179		9,220
Proved undeveloped reserves	—		—
Total Year-end 2015	5,179		9,220
Year-end 2016
Proved developed reserves	446		5,035
Proved undeveloped reserves	—		—
Total Year-end 2016	446		5,035

_____________________


^(a)	Includes natural gas liquids (NGLs).

We do not have any estimated reserves of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas.

At year-end 2016, estimated quantities of proved oil and gas reserves are related to our owned mineral interests which are classified as assets held for sale.

In 2016, we sold oil and gas wells located primarily in Oklahoma, Kansas, Nebraska and North Dakota. Our net reserves for those properties as of year-end 2015 less our share of 2016 production were 4,155,000 barrels of oil, 305,000 barrels of NGL, and 3,756,000 Mcf of gas. Oklahoma properties sold were mainly mature gas wells. Kansas and Nebraska produce oil from the Lansing/Kansas City formation. The North Dakota oil wells produce from the Bakken/Three Forks formation.

In 2015, oil and gas properties having reserves consisting of approximately 704,000 barrels of oil and 1,223,000 Mcf of gas located primarily in the Texas Panhandle and Bakken/Three Forks formations were sold. Due to the significant decline in oil and gas prices during 2015, net negative revisions of previous estimates were 855,000 barrels of oil and 1,995,000 Mcf of gas. At year-end 2015, we had no barrels of oil equivalent (BOE) of proved undeveloped (PUD) reserves based on our plan to exit non-core oil and gas working interest assets compared with 2,703,000 BOE of PUD reserves at year-end 2014.

In 2014, increases in extensions and discoveries of 2,191,000 barrels were primarily associated with new reserves in the Bakken/Three Forks formations. An estimated 694,000 barrels of these extensions and discoveries were associated with new producing wells while a further 913,000 barrels of proved undeveloped reserves were added during 2014. Approximately 105,000 barrels of oil and 218,000 Mcf of gas reserves located primarily in Oklahoma were sold during the year. We realized a net positive revision of previous estimates of 608,000 barrels which is primarily driven by improved drilling results in the Bakken/Three Forks formation yielding higher average estimated ultimate recoverable quantities of proved reserves per well.

In 2015 and 2014, reserve additions from new wells drilled and completed during the year are shown for both consolidated entities and ventures accounted for using the equity method under extensions and discoveries. There were no new well additions in 2016, 36 new well additions in 2015 and 106 new well additions in 2014.

Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized costs related to our oil and gas producing activities classified as assets held for sale at year-end 2016 are as follows:



	At Year-End
	2016			2015
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	374		$	19,441
Proved oil and gas properties	5,159			119,414
Total costs	5,533			138,855
Less accumulated depreciation, depletion and amortization	(4,751		)	(58,242		)
	$	782		$	80,613

We have not capitalized any costs for our share in ventures accounted for using the equity method.

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

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, follows:



	For the Year
	2016		2015		2014
	(In thousands)
Consolidated entities:
Acquisition costs
Proved properties	$	—	$	—	$	2,001
Unproved properties	15		4,832		25,666
Exploration costs	21		17,922		39,399
Development costs	537		27,609		40,277
	$	573	$	50,363	$	107,343

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2015, acquisition of leasehold interests, exploration expenses, and development costs have decreased as a result of our increased focus on exiting and selling our leasehold working interests.

Standardized Measure of Discounted Future Net Cash Flows

Estimates of future cash flows from proved oil and gas reserves are shown in the following table. Estimated income taxes are calculated by applying the appropriate tax rates to the estimated future pre-tax net cash flows less depreciation of the tax basis of properties and the statutory depletion allowance.



	At Year-End
	2016			2015			2014
	(In thousands)
Consolidated entities:
Future cash inflows	$	24,304		$	216,588		$	665,657
Future production and development costs	(2,988		)	(93,623		)	(271,735		)
Future income tax expenses	(3,926		)	(22,218		)	(106,002		)
Future net cash flows	17,390			100,747			287,920
10% annual discount for estimated timing of cash flows	(7,077		)	(33,951		)	(124,079		)
Standardized measure of discounted future net cash flows	$	10,313		$	66,796		$	163,841
Our share in ventures accounted for using the equity method:
Future cash inflows	$	2,010		$	2,283		$	6,186
Future production and development costs	(216		)	(245		)	(664		)
Future income tax expenses	(537		)	(774		)	(2,098		)
Future net cash flows	1,257			1,264			3,424
10% annual discount for estimated timing of cash flows	(585		)	(562		)	(1,649		)
Standardized measure of discounted future net cash flows	$	672		$	702		$	1,775
Total consolidated and our share of equity method ventures	$	10,985		$	67,498		$	165,616

Future net cash flows were computed using prices used in estimating proved oil and gas reserves, year-end costs, and statutory tax rates (adjusted for tax deductions) that relate to proved oil and gas reserves.

Changes in the standardized measure of discounted future net cash flow follows:



	For the Year
	Consolidated			Our Share of Equity Method Ventures			Total
	(In thousands)
Year-end 2013	$	135,553		$	1,300		$	136,853
Changes resulting from:
Net change in sales prices and production costs	(1,064		)	1,571			507
Net change in future development costs	1,308			—			1,308
Sales of oil and gas, net of production costs	(63,192		)	(787		)	(63,979		)
Net change due to extensions and discoveries	58,228			—			58,228
Net change due to acquisition of reserves	2,778			—			2,778
Net change due to divestitures of reserves	(5,804		)	—			(5,804		)
Net change due to revisions of quantity estimates	15,303			(343		)	14,960
Previously estimated development costs incurred	15,497			—			15,497
Accretion of discount	18,067			210			18,277
Net change in timing and other	4,198			115			4,313
Net change in income taxes	(17,031		)	(291		)	(17,322		)
Aggregate change for the year	28,288			475			28,763
Year-end 2014	163,841			1,775			165,616
Changes resulting from:
Net change in sales prices and production costs	(136,536		)	(1,112		)	(137,648		)
Net change in future development costs	92			—			92
Sales of oil and gas, net of production costs	(31,732		)	(428		)	(32,160		)
Net change due to extensions and discoveries	11,747			—			11,747
Net change due to acquisition of reserves	—			—			—
Net change due to divestitures of reserves	(15,855		)	—			(15,855		)
Net change due to revisions of quantity estimates	(15,164		)	(267		)	(15,431		)
Previously estimated development costs incurred	15,096			—			15,096
Accretion of discount	22,600			286			22,886
Net change in timing and other	4,018			(210		)	3,808
Net change in income taxes	48,689			658			49,347
Aggregate change for the year	(97,045		)	(1,073		)	(98,118		)
Year-end 2015	66,796			702			67,498
Changes resulting from:
Net change in sales prices and production costs	(3,585		)	(60		)	(3,645		)
Net change in future development costs	—			—			—
Sales of oil and gas, net of production costs	(5,663		)	(208		)	(5,871		)
Net change due to extensions and discoveries	410			—			410
Net change due to acquisition of reserves	—			—			—
Net change due to divestitures of reserves	(63,535		)				(63,535		)
Net change due to revisions of quantity estimates	1,304			63			1,367
Previously estimated development costs incurred	—			—			—
Accretion of discount	2,992			113			3,105
Net change in timing and other	(128		)	(80		)	(208		)
Net change in income taxes	11,722			142			11,864
Aggregate change for the year	(56,483		)	(30		)	(56,513		)
Year-end 2016	$	10,313		$	672		$	10,985

Results of Operations for Oil and Gas Producing Activities

Our royalty interests are contractually defined and based on a percentage of production at prevailing market prices. We receive our percentage of production in cash. Similarly, for operating properties our working interests and the associated net revenue interests are contractually defined and we pay our proportionate share of the capital and operating costs to develop and operate the well and we market our share of the production. Our revenues fluctuate based on changes in the market prices for oil and gas, the decline in production from existing wells, and other factors affecting oil and gas exploration and production activities, including the cost of development and production.

Information about the results of operations of our oil and gas interests follows:



	For the Year
	2016			2015			2014
	(In thousands)
Consolidated entities
Revenues	$	10,111		$	51,553		$	82,919
Production costs	(4,392		)	(19,820		)	(19,727		)
Exploration costs	(124		)	(11,864		)	(17,416		)
Depreciation, depletion, amortization	(2,157		)	(28,774		)	(29,442		)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests	(612		)	(164,831		)	(32,665		)
Oil and gas administrative expenses	(8,700		)	(11,700		)	(17,000		)
Accretion expense	(56		)	(144		)	(121		)
Income tax (expense) benefit	(20		)	14,717			13,398
Results of operations	(5,950		)	(170,863		)	(20,054		)
Our share in ventures accounted for using the equity method:
Revenues	$	284		$	428		$	786
Production costs	(76		)	(102		)	(105		)
Oil and gas administrative expenses	(35		)	(51		)	(95		)
Income tax (expense) benefit	—			21			(235		)
Results of operations	$	173		$	296		$	351
Total results of operations	$	(5,777	)	$	(170,567	)	$	(19,703	)

Production costs represent our share of oil and gas production severance taxes, and lease operating expenses. Exploration costs principally represent exploratory dry hole costs, geological and geophysical and seismic study costs.