Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)

12 Months Ended

Dec. 31, 2010

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)

Supplemental Financial Data - Oil and Gas Producing Activities (unaudited)

Note 17 — Supplemental Financial Data — Oil and Gas Producing Activities (unaudited)

Estimated Proved Oil and Gas Reserves

On about April 4, 2011, the Company determined that incorrect pricing had been used in the original estimates of its proved oil and gas reserves.  These changes caused an approximate $1.6 million reduction in the standardized measure of discounted future net cash flows compared to the previous estimate provided by the Company.  The following disclosure is reflective of the amended estimates of the Company’s proved oil and gas reserves.

The reserve estimates as of December 31, 2010 and 2009 presented herein were made in accordance with oil and gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009.  This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule, “Modernization of Oil and Gas Reporting,” which was also effective for fiscal years ending on or after December 31, 2009.

The new guidance includes updated definitions of proved oil and gas reserves, proved undeveloped oil and gas reserves, oil and gas producing activities and other terms used in estimating proved oil and gas reserves.  Proved oil and gas reserves as of December 31, 2010 and 2009 were calculated based on the prices for oil and gas during the twelve month period before the reporting date, determined as an un-weighted arithmetic average of the first-day-of-the month price for each month within such period, rather than the year-end spot prices, which had been used in years prior to 2009.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.  The new guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands as well as oil and gas extracted from shales.  Prior period data presented throughout this footnote is not required to be, nor has it been, updated based on the new guidance.

The Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil and gas reserves and changes in its net proved oil and gas reserves for 2010 and 2009 are presented in the table below.  Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.  Existing economic conditions include the average prices for oil and gas during the twelve month period before the reporting date of December 31, 2010 and 2009 and the year-end spot prices for oil and gas for 2008, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  Prices do not include the effects of commodity derivatives.  Existing economic conditions include year-end cost estimates for all years presented.  The reserve information presented below is based on estimates of net proved reserves as of December 31, 2010 and 2009 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC.  The Company does not believe that provisions of the new rules, other than pricing and the five year limitation rule, significantly impacted the reserve estimates in 2009.  The Company does not believe that it is practicable to estimate the effect of applying the new rules on the following tables for reserve quantities or standardized measure of discounted cash flows for the year ended December 31, 2009.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

The Company’s oil and gas properties produce principally natural gas with nominal oil or natural gas liquids.

	2010					2009
	Oil	Natural Gas		Total		Natural Gas
	MBbls	MMcf		MMcfe		MMcf
Proved reserves, beginning of year	—	42,411		42,411		71,406
Revisions of previous estimates	—	1,034		1,034		(35,628	)
Extensions and discoveries	—	23,943		23,943		7,974
Production	—	(1,011	)	(1,011	)	(1,341	)
Purchases of reserves in-place	146	343		1,219		—
Sales of reserves in-place	—	(12,060	)	(12,060	)	—
Proved reserves, end of year	146	54,660		55,536		42,411
Proved developed reserves at:
End of Year	72	17,482		17,914		20,076
Proved undeveloped reserves at:
End of Year	74	37,178		37,622		22,335

For the year ended December 31, 2009, the negative revision of previous estimates of 35,628 MMcfe was primarily due to a 31% decrease in natural gas prices used to calculate proved reserves.  For the year ended December 31, 2010, the increase in extensions and discoveries was due primarily to the Company adopting a policy of including reserves having negative discounted cash flows but positive undiscounted cash flows. As a result, the Company included additional proved undeveloped locations totaling 18.6 Bcfe in 2010 that were not included in 2009. The Company plans to follow this policy in all future reserve disclosures. In addition, the reserves for 2010 include approximately 2.2 Bcfe in new horizontal proved undeveloped locations supported by reliable technology as well as the impact of a $0.40 per Mcf increase in the price of natural gas used to calculate proved reserves.

The portion of the Company's reserves scheduled for production during the next 20, 30 and 40 years are estimated to be 54%, 70% and 80%, respectively.

Aggregate Capitalized Costs

The aggregate capitalized costs relating to oil and gas producing activities at the end of each of the years indicated were as follows:

	2010			2009
	(In thousands)
Oil and gas properties
Proved oil and gas properties	$	43,535		$	60,795
Unproved properties not subject to depletion	2,164			5,135
Accumulated depreciation, depletion, amortization and impairment	(22,121		)	(24,058		)
Net oil and gas properties	$	23,578		$	41,872

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

The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31, 2010 and 2009:

	2010		2009
	(In thousands)
Property acquisition costs:
Unevaluated properties	$	81	$	29
Proved and unproved properties and gathering facilities	1,806		—
Development costs	2,825		3,106
Gathering facilities	—		465
Asset retirement obligation	98		36
Total costs incurred	$	4,810	$	3,636

The Company’s investment in unproved properties as of December 31, 2010, by the year in which such costs were incurred is set forth in the table below:

	2010		2009		2008 and Prior
	(In thousands)
Acquisition costs	$	81	$	29	$	2,054

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities for the years ended December 31, 2010 and 2009 are presented below:

	2010		2009
	(In thousands)
Oil and gas sales, including commodity derivative gains	$	5,571	$	5,903
Expenses:
Production expenses	1,928		2,092
Depletion expense	1,490		2,540
Ceiling test write-down of oil and gas properties	—		16,077
Accretion of asset retirement obligations	17		43
Total expenses	3,435		20,752
Results of operations from oil and gas producing activities	$	2,136	$		(14,849	)
Depletion rate per Mcfe	$	1.47	$	1.89

Standardized Measure of Discounted Future Net Cash Flows

Future oil and gas sales are calculated applying the prices used in estimating the Company’s proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end.  Future production and development costs, which included costs related to plugging of wells, removal of facilities and equipment, and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions.  Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses give effect to tax deductions, credits, and allowances relating to the proved oil and gas reserves.  All cash flow amounts, including income taxes, are discounted at 10%.

Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision.  This table should not be construed to be an estimate of the current market value of the Company’s proved reserves.  Management does not rely upon the information that follows in making investment decisions.

	December 31,
	2010			2009
	(In thousands)
Future cash inflows	$	265,393		$	185,114
Future production costs	(70,659		)	(53,228		)
Future development costs	(60,632		)	(28,675		)
Future income taxes	(41,138		)	(14,282		)
Future net cash flows	92,964			88,929
10% annual discount	(72,012		)	(62,508		)
Standardized measure of discounted future net cash flows	$	20,952		$	26,421

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last two years is as follows:

	December 31,
	2010			2009
	(In thousands)
Standardized measure of discounted future net cash flows, beginning of year	$	26,421		$	51,201
Sales of oil and gas, net of production costs and taxes	(2,951		)	(3,584		)
Price revisions	2,270			(28,243		)
Extensions, discoveries and improved recovery, less related costs	(1,915		)	1,926
Changes in estimated future development costs	1,214			32,710
Development costs incurred during the period	753			2,481
Quantity revisions	903			(21,773		)
Accretion of discount	2,642			5,642
Net changes in future income taxes	—			(5,251		)
Purchases of reserves-in-place	2,178			—
Sales of reserves-in-place	(8,834		)	—
Changes in production rates (timing) and other	(1,729		)	(8,688		)
Standardized measure of discounted future net cash flows, end of year	$	20,952		$	26,421

The computation of the standardized measure of discounted future net cash flows relating to proved gas reserves at December 31, 2010 and 2009 were based on the average of the first-day-of-the-month NYMEX (close) price during the twelve-month period prior to December 31, 2010 and 2009 of $4.393 and $3.956 per MMBtu, respectively, and year-end costs.  The twelve month weighted average adjusted natural gas price during the twelve month period prior to December 31, 2010 and 2009 were $4.656 and $4.362 per Mcf, respectively.