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 2017, we had divested 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 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. In addition, we have sold our remaining mineral assets and no longer own any oil and gas or mineral assets.

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

These estimates were based on the economic and operating conditions existing at year-end 2016 and 2015. 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.

For 2016 and 2015, the primary internal technical person in charge of overseeing our reserves estimates had a Bachelor of Science in Physics and Mathematics and a Master's of Science in Civil Engineering. He had over 40 years of domestic and international experience in the exploration and production business including 40 years of reserve evaluations. He had been a registered Professional Engineer for over 25 years.

As part of our internal control over financial reporting, for 2016 and 2015 we had a process for reviewing well production data and division of interest percentages prior to submitting well level data to NSAI to assist us in preparing reserve estimates. Our primary internal technical person and other members of management reviewed the reserve estimates prepared by NSAI, including the underlying assumptions and estimates upon which they are based, for accuracy and reasonableness.

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 were 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 and 2015, the average spot price per barrel of oil based on the West Texas Intermediate price was $42.75 and $50.28 and the average price per MMBTU of gas based on the Henry Hub spot was $2.48 and $2.59. 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 were imprecise and could be expected to change as future information became available.

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 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
Revisions of previous estimates	—		—
Extensions and discoveries	—		—
Acquisitions	—		—
Sales	(446	)	(3,836	)
Production	—		—
Year-end 2017	—		—
Our share of ventures accounted for using the equity method:
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
Sales	—		(1,199	)
Year-end 2017	—		—
Total consolidated and our share of equity method ventures:
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
Year-end 2017
Proved developed reserves	—		—
Proved undeveloped reserves	—		—
Total Year-end 2017	—		—

_____________________


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

We did not have any estimated reserves or wells with production of synthetic oil, synthetic gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and gas as of year-end 2017, 2016 or 2015.

In 2017, we sold oil and gas wells located primarily in Texas and Louisiana. Our net reserves for those properties as of year-end 2016 were 446,000 barrels of oil and 5,035,000 Mcf of gas.

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 2016 and 2015, 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 2017, no new well additions in 2016 and 36 new well additions in 2015.

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
	2017		2016
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	—	$	374
Proved oil and gas properties	—		5,159
Total costs	—		5,533
Less accumulated depreciation, depletion and amortization	—		(4,751		)
	$	—	$	782

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
	2017		2016		2015
	(In thousands)
Consolidated entities:
Acquisition costs
Proved properties	$	—	$	—	$	—
Unproved properties	—		15		4,832
Exploration costs	—		21		17,922
Development costs	—		537		27,609
	$	—	$	573	$	50,363

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.

Drilling and Other Exploratory and Development Activities

The following tables set forth the number of gross and net oil and gas wells in which we participated:



Gross Wells
		Exploratory			Development
Year	Total	Oil	Gas	Dry	Oil	Gas	Dry
2017	—	—	—	—	—	—	—
2016	—	—	—	—	—	—	—
2015 (a)	38	2	—	1	34	—	1

_____________________


^(a)	Of the gross wells drilled in 2015, we operated 3 wells or 8 percent. The remaining wells represent our participations in wells operated by others. The exploratory dry hole was located in Oklahoma.



Net Wells
		Exploratory			Development
Year	Total	Oil	Gas	Dry	Oil	Gas	Dry
2017	—	—	—	—	—	—	—
2016	—	—	—	—	—	—	—
2015	6.3	0.7	—	0.8	4.3	—	0.5

Present Activities

None.

Delivery Commitments

We have no oil or gas delivery commitments.

Wells and Acreage

We had no interest in any productive wells as of year-end 2017.

At year-end 2017, 2016 and 2015, we had royalty interests in 0, 473 and 534 gross wells. In addition, at year-end 2017, 2016 and 2015, we had working interests in 0, 32 and 400 gross wells.

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
	2017		2016			2015
	(In thousands)
Consolidated entities:
Future cash inflows	$	—	$	24,304		$	216,588
Future production and development costs	—		(2,988		)	(93,623		)
Future income tax expenses	—		(3,926		)	(22,218		)
Future net cash flows	—		17,390			100,747
10% annual discount for estimated timing of cash flows	—		(7,077		)	(33,951		)
Standardized measure of discounted future net cash flows	$	—	$	10,313		$	66,796
Our share in ventures accounted for using the equity method:
Future cash inflows	$	—	$	2,010		$	2,283
Future production and development costs	—		(216		)	(245		)
Future income tax expenses	—		(537		)	(774		)
Future net cash flows	—		1,257			1,264
10% annual discount for estimated timing of cash flows	—		(585		)	(562		)
Standardized measure of discounted future net cash flows	$	—	$	672		$	702
Total consolidated and our share of equity method ventures	$	—	$	10,985		$	67,498

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 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
Changes resulting from:
Net change in sales prices and production costs	—			—			—
Net change in future development costs	—			—			—
Sales of oil and gas, net of production costs	—			—			—
Net change due to extensions and discoveries	—			—			—
Net change due to acquisition of reserves	—			—			—
Net change due to divestitures of reserves	(10,313		)	(672		)	(10,985		)
Net change due to revisions of quantity estimates	—			—			—
Previously estimated development costs incurred	—			—			—
Accretion of discount	—			—			—
Net change in timing and other	—			—			—
Net change in income taxes	—			—			—
Aggregate change for the year	(10,313		)	(672		)	(10,985		)
Year-end 2017	$	—		$	—		$	—

Results of Operations for Oil and Gas Producing Activities

Our royalty interests were contractually defined and based on a percentage of production at prevailing market prices. We received our percentage of production in cash. Similarly, for operating properties our working interests and the associated net revenue interests were contractually defined and we paid our proportionate share of the capital and operating costs to develop and operate the well and we marketed our share of the production. Our revenues fluctuated 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
	2017			2016			2015
	(In thousands)
Consolidated entities
Revenues	$	1,399		$	10,111		$	51,553
Production costs	(209		)	(4,392		)	(19,820		)
Exploration costs	(34		)	(124		)	(11,864		)
Depreciation, depletion, amortization	—			(2,157		)	(28,774		)
Non-cash impairment of proved oil and gas properties and unproved leasehold interests	(224		)	(612		)	(164,831		)
Oil and gas administrative expenses	(1,197		)	(8,700		)	(11,700		)
Accretion expense	—			(56		)	(144		)
Income tax (expense) benefit	(7		)	(20		)	14,717
Results of operations	(272		)	(5,950		)	(170,863		)
Our share in ventures accounted for using the equity method:
Revenues	$	100		$	284		$	428
Production costs	(19		)	(76		)	(102		)
Oil and gas administrative expenses	(2		)	(35		)	(51		)
Income tax (expense) benefit	—			—			21
Results of operations	$	79		$	173		$	296
Total results of operations	$	(193	)	$	(5,777	)	$	(170,567	)

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.