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Supplemental Oil and Natural Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2011

Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]

Supplemental Oil and Natural Gas Disclosures (Unaudited)

Note 21 — Supplemental Oil and Natural Gas Disclosures (Unaudited)

The following unaudited information regarding our oil and natural 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 natural 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 non-operating 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 are also taking steps to become an operator with respect to oil and natural gas drilling and producing activities.

We engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc., to prepare estimates of our proved developed oil and natural gas reserves, all of which are located in the U.S., and future net cash flows as of year-end 2011, 2010 and 2009. These estimates were based on the economic and operating conditions existing at year-end 2011, 2010 and 2009. 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. This reserve information does not include estimates of reserves and future cash flows associated with proved undeveloped reserves or any potential value related to our over 563,000 undeveloped mineral acres because, at year-end 2011, we are solely royalty and minority non-operating working interest owners and as a result we do not determine whether or when undeveloped reserves will be converted to developed reserves.

In December 2009, we adopted revised oil and natural gas reserve estimation and disclosure requirements to conform to the SEC “Modernization of Oil and Gas Reporting” rules. The 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 are also 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 2011, 2010 and 2009, the average price per barrel of oil based on the West Texas Intermediate Crude price is $92.71, $75.96 and $57.65 and the average price per MMBTU of natural gas based on the Henry Hub spot market is $4.12, $4.38 and $3.87. All prices were 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 natural 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 developed reserves.

Estimated Quantities of Proved Developed Oil and Natural Gas Reserves

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

		Net Reserves
		Oil				Natural Gas
		(Barrels)				(Mcf)
		(In thousands)
Consolidated entities:
Year-end 2008			457				7,538
Revisions of previous estimates			171				(484	)
Extensions and discoveries			59				1,018
Production			(107	)			(1,412	)
Year-end 2009			580				6,660
Revisions of previous estimates			123				709
Extensions and discoveries			21				514
Production			(115	)			(1,224	)
Year-end 2010			609				6,659
Revisions of previous estimates			197				3
Extensions and discoveries			410				2,670
Production			(152	)			(1,129	)
Year-end 2011			1,064				8,203
Our share of ventures accounted for using the equity method:
Year-end 2008			—				125
Revisions of previous estimates			—				2
Extensions and discoveries			—				2,463
Production			—				(82	)
Year-end 2009			—				2,508
Revisions of previous estimates			—				1,041
Extensions and discoveries			—				895
Production			—				(573	)
Year-end 2010			—				3,871
Revisions of previous estimates			—				(95	)
Extensions and discoveries			—				—
Production			—				(493	)
Year-end 2011			—				3,283
Total consolidated and our share of equity method ventures:
Year-end 2009			580				9,168
Year-end 2010			609				10,530
Year-end 2011			1,064				11,486

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

In 2011, increases in oil prices accounted for about 28,000 barrels of the upward revisions in oil reserves for our consolidated entities. The remaining upward revisions to oil reserves were attributable to continued improved response from a steam injection program, improved operational efficiencies from water drive reservoirs, improved performance of recently completed oil wells and generally from improved production performances as a result of more efficient operations driven by higher oil prices.

In 2010, increases in oil and natural gas prices accounted for about 27,000 barrels and about 475,000 Mcf of upward revisions in reserves for our consolidated entities. The remaining upward revisions to oil reserves were attributable to improved performance of natural water drive reservoirs, response from a lease steam injection program, a work-over and installation of gas lift valves on a high volume and high royalty interest well, improved performance from a well that came online in late 2009 and the associated natural gas liquids, reactivation of two abandoned oil wells, two recompletions, and generally from improved production performances as a result of more efficient operations driven by higher oil prices. The balance of the upward revisions to natural gas reserves is attributable to the associated natural gas from the upward revisions in oil reserves. For ventures accounted for by the equity method, increases in natural gas prices accounted for about 46,000 Mcf of the upward revisions in natural gas reserves and the remaining upward revisions in natural gas reserves are from better than expected performance from nine Barnett Shale wells that were classified as proved developed non-producing at year-end 2009. These long-lateral horizontal wells began production in first quarter 2010.

In 2009, the upward revision in oil reserves was predominately attributable to stimulation treatments to two existing wells, remedial work on a high volume oil well, improved performance from a change in the operating conditions of a natural water drive reservoir, addition of natural gas liquids reserves and reactivation of idle oil wells. The downward revision in natural gas reserves is largely due to accounting for consumption of natural gas in operations and sale of dry natural gas volumes. This consumption of natural gas, shrink of natural gas due to processing, and the amounts of natural gas liquids production and sales, were not known when estimating reserves for year-end 2008 as our new processes to obtain such information were not in place.

In 2011, 2010 and 2009, 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 36 new well additions in 2011, 22 new well additions in 2010 and 30 new well additions in 2009.

In 2009, the effect of applying twelve month average prices, versus 2009 year-end prices of $76.00 per barrel and $5.79 per MMBTU of natural gas, decreased net remaining reserve volumes by 8 percent of total proved reserves. We do not have any estimated reserves of synthetic oil, synthetic natural gas or products of other non-renewable natural resources that are intended to be upgraded into synthetic oil and natural gas.

Capitalized Cost Relating to Oil and Natural Gas Producing Activities

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

		At Year-End
		2011				2010				2009
		(In thousands)
Consolidated entities:
Proved oil and natural gas properties		$	4,002			$	456			$	450
Unproved oil and natural gas properties			714				—				—
Accumulated depreciation, depletion and amortization			(155	)			(134	)			(69	)
Net capitalized costs		$	4,561			$	322			$	381

We have not capitalized any costs for our share in ventures accounted for using the equity method. Proved oil and natural gas properties increased in 2011 due to our participation as a non-operating working interest owner in two wells. Unproved oil and natural gas properties increased as a result of our acquisition of unproved leasehold on approximately 13,000 net mineral acres in Alabama and Georgia. Accumulated depreciation, depletion and amortization represents our proportional share of exploration and development costs related to our non-operating working interest in wells that began production in 2009 and 2011.

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

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

		For the Year
		2011				2010				2009
		(In thousands)
Consolidated entities:
Acquisition of properties		$	714			$	—			$	—
Exploration costs			549				—				209
Development costs			3,597				5				215
Total cost incurred for consolidated entities		$	4,860			$	5			$	424

We have not incurred any costs for our share in ventures accounted for using the equity method. Acquisition of properties represents unproved leasehold associated with 13,000 net mineral acres in Alabama and Georgia acquired in 2011. Development costs have increased due to our participation as a non-operating working interest owner in two wells during 2011.

Standardized Measure of Discounted Future Net Cash Flows

Estimates of future cash flows from proved developed oil and natural 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
		2011				2010				2009
		(In thousands)
Consolidated entities:
Future cash inflows		$	142,043			$	74,264			$	57,416
Future production and development costs			(18,929	)			(9,003	)			(8,379	)
Future income tax expenses			(38,681	)			(20,570	)			(15,362	)
Future net cash flows			84,433				44,691				33,675
10% annual discount for estimated timing of cash flows			(31,735	)			(17,881	)			(12,537	)
Standardized measure of discounted future net cash flows		$	52,698			$	26,810			$	21,138
Our share in ventures accounted for using the equity method:
Future cash inflows		$	12,346			$	15,748			$	8,265
Future production and development costs			(1,731	)			(3,545	)			(886	)
Future income tax expenses			(3,154	)			(3,542	)			(2,333	)
Future net cash flows			7,461				8,661				5,046
10% annual discount for estimated timing of cash flows			(3,953	)			(4,334	)			(2,374	)
Standardized measure of discounted future net cash flows		$	3,508			$	4,327			$	2,672
Total consolidated and our share of equity method ventures		$	56,206			$	31,137			$	23,810

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

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

		For the Year
		Consolidated				Our Share of Equity Method Ventures				Total
		(In thousands)
Year-end 2008		$	21,885			$	188			$	22,073
Changes resulting from:
Net change in sales prices and production costs			(3,043	)			(97	)			(3,140	)
Sales of oil and natural gas, net of production costs			(11,157	)			(299	)			(11,456	)
Net change due to extensions and discoveries			4,139				3,844				7,983
Net change due to revisions of quantity estimates			5,693				1,169				6,862
Accretion of discount			2,408				21				2,429
Net change in income taxes			1,213				(2,154	)			(941	)
Aggregate change for the year		$	(747	)		$	2,484			$	1,737
Year-end 2009		$	21,138			$	2,672			$	23,810
Changes resulting from:
Net change in sales prices and production costs			9,929				939				10,868
Sales of oil and natural gas, net of production costs			(12,690	)			(2,104	)			(14,794	)
Net change due to extensions and discoveries			2,148				1,526				3,674
Net change due to revisions of quantity estimates			9,153				2,224				11,377
Accretion of discount			2,340				279				2,619
Net change in income taxes			(5,208	)			(1,209	)			(6,417	)
Aggregate change for the year		$	5,672			$	1,655			$	7,327
Year-end 2010		$	26,810			$	4,327			$	31,137
Changes resulting from:
Net change in sales prices and production costs			8,476				153				8,629
Sales of oil and natural gas, net of production costs			(17,747	)			(1,622	)			(19,369	)
Net change due to extensions and discoveries			32,671				—				32,671
Net change due to revisions of quantity estimates			17,586				(204	)			17,382
Accretion of discount			3,013				466				3,479
Net change in income taxes			(18,111	)			388				(17,723	)
Aggregate change for the year		$	25,888			$	(819	)		$	25,069
Year-end 2011		$	52,698			$	3,508			$	56,206

Results of Operations for Oil and Natural 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. Our royalty revenues fluctuate based on changes in the market prices for oil and natural gas, the inevitable decline in production in existing wells, and other factors affecting the third-party oil and natural gas exploration and production companies, including the cost of development and production.

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

		For the Year
		2011				2010				2009
		(In thousands)
Consolidated entities:
Royalty revenues		$	19,239			$	13,724			$	11,910
Production costs			(1,492	)			(1,032	)			(753	)
Exploration expenses			(549	)			—				(100	)
Depreciation, depletion, amortization			(337	)			(334	)			(253	)
Oil and natural gas administrative expenses			(4,445	)			(3,295	)			(3,546	)
Income tax expenses			(3,645	)			(2,637	)			(2,200	)
Results of operations		$	8,771			$	6,426			$	5,058
Our share in ventures accounted for using the equity method:(a)
Royalty revenues		$	1,882			$	2,359			$	312
Production costs			(260	)			(255	)			(13	)
Exploration expenses			—				—				—
Depreciation, depletion, amortization			—				—				—
Oil and natural gas administrative expenses			(228	)			(70	)			(18	)
Income tax expenses			(400	)			(605	)			(84	)
Results of operations		$	994			$	1,429			$	197
Total results of operations		$	9,765			$	7,855			$	5,255

^(a)  Producing wells in ventures accounted for using the equity method began generating royalties in 2009.

Production costs represent our share of oil and natural gas production severance taxes and lease operating expenses.

Oil and natural gas produced and average unit prices related to our royalty and non-operating working interests follows:

		For the Year
		2011				2010				2009
Consolidated entities:
Oil production (barrels)			151,900				115,400				107,200
Average price per barrel		$	96.84			$	73.09			$	56.85
Natural gas production (millions of cubic feet)			1,128.6				1,223.6				1,411.6
Average price per thousand cubic feet		$	4.01			$	4.32			$	4.12
Our share of ventures accounted for using the equity method:
Natural gas production (millions of cubic feet)			493.4				572.8				82.1
Average price per thousand cubic feet		$	3.81			$	4.12			$	3.80
Total consolidated and our share of equity method ventures:
Oil production (barrels)			151,900				115,400				107,200
Average price per barrel		$	96.84			$	73.09			$	56.85
Natural gas production (millions of cubic feet)			1,622.0				1,796.4				1,493.7
Average price per thousand cubic feet		$	3.95			$	4.26			$	4.10

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- Definition

The entire disclosure for oil and gas producing industries.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef

-Publisher FASB

-Name Statement of Financial Accounting Standard (FAS)

-Number 19

-Paragraph 59A-59Z, 59AA, 59BB, 59CC

-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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