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).

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.

In 2012, we acquired 100 percent of the outstanding common stock of Credo in an all cash transaction for $14.50 per share, representing an equity purchase price of approximately $146,445,000. In addition, we paid in full $8,770,000 of Credo’s outstanding debt. Credo was an independent oil and gas exploration, development and production company based in Denver, Colorado. The acquired assets included leasehold interests in the Bakken and Three Forks formations of North Dakota, the Lansing – Kansas City formation in Kansas and Nebraska, and the Tonkawa and Cleveland formations in Texas.

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 2014, 2013 and 2012.

These estimates were based on the economic and operating conditions existing at year-end 2014, 2013 and 2012. 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 2014, 2013 and 2012, the average spot price per barrel of oil based on the West Texas Intermediate Crude price is $94.99, $96.91 and $94.71 and the average price per MMBTU of gas based on the Henry Hub spot market is $4.35, $3.67 and $2.76. All prices were then adjusted for quality, transportation fees and regional price 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 2011	1,064		8,203
Revisions of previous estimates	45		(2,163	)
Extensions and discoveries	86		241
Acquisitions	2,396		7,109
Production	(371	)	(1,668	)
Year-end 2012	3,220		11,722
Revisions of previous estimates	182		1,243
Extensions and discoveries	3,085		2,046
Acquisitions	35		531
Production	(698	)	(1,912	)
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
Our share of ventures accounted for using the equity method:
Year-end 2011	—		3,283
Revisions of previous estimates	—		(390	)
Production	—		(321	)
Year-end 2012	—		2,572
Revisions of previous estimates	—		7
Production	—		(247	)
Year-end 2013	—		2,332
Revisions of previous estimates	—		(382	)
Production	—		(199	)
Year-end 2014	—		1,751
Total consolidated and our share of equity method ventures:
Year-end 2012
Proved developed reserves	2,416		13,020
Proved undeveloped reserves	804		1,274
Total Year-end 2012	3,220		14,294
Year-end 2013
Proved developed reserves	3,893		13,717
Proved undeveloped reserves	1,931		2,245
Total Year-end 2013	5,824		15,962
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

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^(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.

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 2013, increase in gas prices accounted for about 1,243,000 Mcf of upward revisions in gas reserves for our consolidated entities.

In 2012, decreases in gas prices accounted for about 800,000 Mcf of downward revisions in gas reserves for our consolidated entities and about 330,000 Mcf of downward revisions for our equity method ventures. The remaining downward revisions in gas reserves for our consolidated entities were attributable to adverse performance from reducing the total fluid withdrawal rate in a natural water drive reservoir, adverse performance from increasing total fluid withdrawal rate in another natural water drive reservoir, from unfavorable performance from newer wells in over-pressured reservoirs that are exhibiting pressure-dependent permeability reductions, and generally due to higher operating pressures adversely affecting gas well performances in a higher back-pressure environment.

In 2014, 2013 and 2012, 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 for the royalty interest wells and in 2012 with the acquisition of Credo, working interest wells apply industry practices for new well classifications. There were 106 new well additions in 2014, 88 new well additions in 2013 and 27 new well additions in 2012.

Capitalized Costs Relating to Oil and Gas Producing Activities

Capitalized costs related to our oil and gas producing activities are as follows:



	At Year-End
	2014			2013
	(In thousands)
Consolidated entities:
Unproved oil and gas properties	$	90,446		$	100,320
Proved oil and gas properties	221,299			155,262
Total costs	311,745			255,582
Less accumulated depreciation, depletion and amortization	(48,252		)	(22,941		)
	$	263,493		$	232,641

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
	2014		2013		2012
	(In thousands)
Consolidated entities:
Acquisition costs:
Proved properties	$	2,001	$	—	$	—
Unproved properties	25,666		35,806		4,418
Exploration costs	39,399		10,486		1,752
Development costs	40,277		54,538		15,938
	$	107,343	$	100,830	$	22,108

We have not incurred any costs for our share in ventures accounted for using the equity method. In 2014 and 2013, acquisition of leasehold interests, exploration expenses, and development costs have increased as a result of our increased focus to increase production, reserves, and also to explore and develop the assets acquired from Credo.

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
	2014			2013			2012
	(In thousands)
Consolidated entities:
Future cash inflows	$	665,657		$	544,098		$	322,098
Future production and development costs	(271,735		)	(231,801		)	(104,441		)
Future income tax expenses	(106,002		)	(77,361		)	(50,350		)
Future net cash flows	287,920			234,936			167,307
10% annual discount for estimated timing of cash flows	(124,079		)	(99,383		)	(60,764		)
Standardized measure of discounted future net cash flows	$	163,841		$	135,553		$	106,543
Our share in ventures accounted for using the equity method:
Future cash inflows	$	6,186		$	4,765		$	5,125
Future production and development costs	(664		)	(512		)	(551		)
Future income tax expenses	(2,098		)	(1,616		)	(1,738		)
Future net cash flows	3,424			2,637			2,836
10% annual discount for estimated timing of cash flows	(1,649		)	(1,337		)	(1,423		)
Standardized measure of discounted future net cash flows	$	1,775		$	1,300		$	1,413
Total consolidated and our share of equity method ventures	$	165,616		$	136,853		$	107,956

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 2011	$	52,698		$	3,508		$	56,206
Changes resulting from:
Net change in sales prices and production costs	(5,709		)	(2,497		)	(8,206		)
Net change in future development costs	(1,834		)	—			(1,834		)
Sales of oil and gas, net of production costs	(31,732		)	(632		)	(32,364		)
Net change due to extensions and discoveries	5,596			—			5,596
Net change due to acquisition of reserves	86,013			—			86,013
Net change due to revisions of quantity estimates	(2,254		)	18			(2,236		)
Previously estimated development costs incurred	1,007			—			1,007
Accretion of discount	7,377			401			7,778
Net change in income taxes	(4,619		)	615			(4,004		)
Aggregate change for the year	53,845			(2,095		)	51,750
Year-end 2012	106,543			1,413			107,956
Changes resulting from:
Net change in sales prices and production costs	23,422			415			23,837
Net change in future development costs	(2,897		)	—			(2,897		)
Sales of oil and gas, net of production costs	(56,559		)	(801		)	(57,360		)
Net change due to extensions and discoveries	54,539			—			54,539
Net change due to acquisition of reserves	1,160			—			1,160
Net change due to revisions of quantity estimates	8,673			6			8,679
Previously estimated development costs incurred	4,124			—			4,124
Accretion of discount	13,540			228			13,768
Net change in timing and other	(718		)	(31		)	(749		)
Net change in income taxes	(16,274		)	70			(16,204		)
Aggregate change for the year	29,010			(113		)	28,897
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

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, 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
	2014			2013			2012
	(In thousands)
Consolidated entities^(a)
Revenues	$	82,919		$	69,036		$	36,204
Production costs	(19,727		)	(12,477		)	(4,472		)
Exploration costs	(17,416		)	(10,486		)	(1,754		)
Depreciation, depletion, amortization	(29,442		)	(19,552		)	(4,905		)
Non-cash impairments	(32,665		)	(473		)	—
Oil and gas administrative expenses	(17,000		)	(14,407		)	(8,332		)
Accretion expense	(121		)	(94		)	(26		)
Income tax expenses	13,398			(3,471		)	(4,841		)
Results of operations	(20,054		)	8,076			11,874
Our share in ventures accounted for using the equity method:
Revenues	$	786		$	801		$	770
Production costs	(105		)	(123		)	(138		)
Oil and gas administrative expenses	(95		)	(86		)	(123		)
Income tax expenses	(235		)	(178		)	(147		)
Results of operations	$	351		$	414		$	362
Total results of operations	$	(19,703	)	$	8,490		$	12,236

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^(a)	2012 includes only three months of operations from Credo due to our third quarter 2012 acquisition.

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.