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Supplementary Information

12 Months Ended

Dec. 31, 2012

Supplementary Information [Abstract]

Supplementary Information

SUPPLEMENTARY INFORMATION

CAPITALIZED COSTS RELATING TO

OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2012 and 2011

(Unaudited)


	As of December 31,
(Thousands of dollars)	2012		2011
Proved Developed oil and gas properties	$	336,135	$	491,938
Proved Undeveloped oil and gas properties		2,069		455
Unproved oil and gas properties		—		—

Total Capitalized Costs		338,204		492,393
Accumulated depreciation, depletion and valuation allowance		150,276		355,643

Net Capitalized Costs	$	187,928	$	136,750

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,

EXPLORATION AND DEVELOPMENT ACTIVITIES

Years Ended December 31, 2012 and 2011

(Unaudited)


	Year Ended December 31,
(Thousands of dollars)	2012		2011
Acquisition of Properties, Developed	$	6,482	$	273
Acquisition of Properties, Undeveloped		2,030		146
Exploration Costs		10		38
Development Costs		66,671		38,820

See accompanying Notes to Supplementary Information

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2012 and 2011

(Unaudited)


	As of December 31,
(Thousands of dollars)	2012			2011
Future cash inflows	$	1,524,137		$	1,113,603
Future production costs		(673,629	)		(530,237	)
Future development costs		(179,568	)		(67,158	)
Future income tax expenses		(186,072	)		(148,283	)

Future Net Cash Flows		484,868			367,925
10% annual discount for estimated timing of cash flows		(271,595	)		(183,417	)

Standardized Measure of Discounted Future Net Cash Flows	$	213,273		$	184,508

STANDARDIZED MEASURE OF DISCOUNTED FUTURE

NET CASH FLOWS AND CHANGES THEREIN

RELATING TO PROVED OIL AND GAS RESERVES

Years Ended December 31, 2012 and 2011

(Unaudited)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2012 and 2011:


	Year Ended December 31,
(Thousands of dollars)	2012			2011
Sales of oil and gas produced, net of production costs	$	(48,673	)	$	(59,133	)
Net changes in prices and production costs		504			77,637
Extensions, discoveries and improved recovery		164,557			49,108
Revisions of previous quantity estimates		40,964			8,579
Net change in development costs		(145,382	)		(30,834	)
Reserves sold		—			—
Reserves purchased		6,563			—
Accretion of discount		18,451			14,648
Net change in income taxes		(5,952	)		(20,342	)
Changes in production rates (timing) and other		(2,267	)		(1,639	)

Net change		28,765			38,024
Standardized measure of discounted future net cash flow:
Beginning of year		184,508			146,484

End of year	$	213,273		$	184,508

See accompanying Notes to Supplementary Information

RESERVE QUANTITY INFORMATION

Years Ended December 31, 2012 and 2011

(Unaudited)


	As of December 31,
	2012									2011
	Oil (MBbls)			NGLs (MBbls)			Gas (MMcf)			Oil (MBbls)			Gas (MMcf)
					(a	)
Proved Developed Reserves:
Beginning of year		6,418			—			43,631			5,233			41,946
Extensions, discoveries and improved recovery		224			49			1,000			836			3,536
Revisions of previous estimates		252			2,860			(15,821	)		273			121
Converted from undeveloped reserves		861			—			3,527			704			3,028
Reserves sold		—			—			—			—			—
Reserves purchased		168			—			211			—			—
Production		(745	)		—			(4,715	)		(628	)		(5,000	)

End of year		7,178			2,909			27,833			6,418			43,631

Proved Undeveloped Reserves:
Beginning of year		2,435			—			9,765			2,652			11,400
Extensions, discoveries and improved recovery		3,446			1,401			6,158			460			1,955
Revisions of previous estimates		887			1,476			217			27			(562	)
Converted to developed reserves		(861	)		—			(3,527	)		(704	)		(3,028	)
Reserves sold		—			—			—			—			—
Reserves purchased		—			—			—			—			—

End of year		5,907			2,877			12,613			2,435			9,765

Total Proved Reserves at the End of the Year		13,085			5,786			40,446			8,853			53,396

(a)	Prior to December 31, 2012, natural gas liquids (NGLs) were included in the oil and gas reserve reports under the natural gas heading using a standard conversion factor of one barrel of NGLs to six thousand cubic feet (Mcf) of gas.

See accompanying Notes to Supplementary Information

RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES

Years Ended December 31, 2012 and 2011

(Unaudited)


	Year Ended December 31,
(Thousands of dollars)	2012		2011
Revenue:
Oil and gas sales	$	88,336	$	96,030
Costs and Expenses:
Lease operating expenses		39,868		36,897
Exploration costs		10		38
Depreciation and depletion		19,883		42,282
Income tax expense		8,941		3,200

Total Costs and Expenses		68,702		82,417

Results of Operations From Producing Activities (excluding corporate overhead and interest costs)	$	19,634	$	13,613

See accompanying Notes to Supplementary Information

1. Presentation of Reserve Disclosure Information

Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of the Company’s reserves.

2. Determination of Proved Reserves

The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs.

3. Results of Operations from Oil and Gas Producing Activities

The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities.

4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles.

Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves.

Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the year-end U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves.

Future net cash flows are discounted at a rate of 10% annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10% discount figure is arbitrary.

5. Changes in Reserves

The 2012 and 2011 extensions and discoveries reflect the successful drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.