Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)

12 Months Ended

Dec. 31, 2011

Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)

Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)

7. Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)

Capitalized Costs

The following table presents the Partnership’s aggregate capitalized costs relating to oil and gas activities at the end of each of the years indicated:

December 31,	2011			2010			2009
Oil and natural gas properties:
Proved properties	$	13,246,115		$	21,979,751		$	21,602,365
	13,246,115			21,979,751			21,602,365
Less:
Accumulated depreciation, depletion and amortization	(2,463,179		)	(3,569,405		)	(3,029,089		)
Property impairment	(10,282,343		)	(17,249,916		)	(17,249,916		)
Total	$	500,593		$	1,160,430		$	1,323,360

Costs Incurred

The following table sets forth costs incurred in oil and gas exploration and development activities during the years ended December 31, 2011, 2010, and 2009:

	2011			2010		2009
Oil and natural gas properties:
Exploration	$	(1,809	)	$	9,200	$	59,641
Development	35,510			368,185		137,621
Total	$	33,701		$	377,385	$	197,262

Results of Operations

The following table sets forth results of operations from oil and gas producing activities for the years ended December 31, 2011, 2010, and 2009.

	2011			2010			2009
Oil and gas producing activities:
Oil sales	$	917,019		$	1,036,282		$	827,273
Natural gas sales	241,530			485,595			590,024
Production expenses	(350,905		)	(315,265		)	(309,310		)
Accretion of asset retirement obligation	(12,182		)	(16,448		)	(18,722		)
Depreciation , depletion and amortization	(313,136		)	(540,316		)	(606,787		)
Property impairment expense	—			—			(566,679		)
Results of operations from producing activities	$	482,326		$	649,848		$	(84,201	)
Depletion rate per BOE	$	16.91		$	17.78		$	15.70

BOE = Barrels of Oil Equivalent (6 MCF equals 1 BOE)

Crude Oil and Natural Gas Reserves

Net Proved Developed Reserve Summary

The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firms Forrest A. Garb & Associates, Inc., as of December 31, 2011, 2010 and 2009.  A copy of the Forrest A. Garb & Associates summary reserve report is included as Exhibit 99.1 to this Annual Report.  Proved crude oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  At December 31, 2011, all of the Partnership’s reserves are classified as proved developed reserves.  All of the Partnership’s reserves are located in the United States.

The following table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2011, 2010, and 2009.

	Oil(BBL) (1)		Gas(mcf)		BOE (2)
Net proved reserves for properties owned by the Partnership
Reserves at December 31, 2008	33,393		402,122		100,413
Revisions of previous estimates	23,517		(73,479	)	11,270
Production	(15,200	)	(140,623	)	(38,637	)
Reserves at December 31, 2009	41,710		188,020		73,046
Revisions of previous estimates	20,258		139,882		43,572
Production	(14,268	)	(96,722	)	(30,388	)
Reserves at December 31, 2010	47,700		231,180		86,230
Reserves sold	(32,473	)	(74,438	)	(44,880	)
Revisions of previous estimates	1,469		(15,246	)	(1,071	)
Production	(10,056	)	(50,796	)	(18,522	)
Reserves at December 31, 2011	6,640		90,700		21,757

(1)	Oil includes both oil and natural gas liquids
(2)	BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.  The Partnership believes such information is essential for a proper understanding and assessment of the data presented.

For the year ended December 31, 2011, calculations were made using average prices of $95.84 per barrel of crude oil and $4.15 per MCF of natural gas. For the year ended December 31, 2010, calculations were made using average prices of $79.79 per barrel of crude oil and $4.39 per MCF of natural gas. For the year ended December 31, 2009, calculations were made using average prices of $61.08 per barrel of crude oil and $3.83 per MCF of natural gas. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.

These assumptions used to compute estimated future cash inflows do not necessarily reflect Reef’s expectations of the Partnership’s actual revenues or costs, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.

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

A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.

December 31,	2011			2010			2009
Crude oil and natural gas properties owned by the Partnership:
Future cash inflows	$	1,076,880		$	4,998,080		$	3,245,780
Future production costs	(324,970		)	(2,355,900		)	(1,600,550		)
Future development costs	—			—			(89,200		)
Future net cash flows	751,910			2,642,180			1,556,030
Effect of discounting net cash flows at 10%	(96,690		)	(544,380		)	(232,670		)
Discounted future net cash flows	$	655,220		$	2,097,800		$	1,323,360

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

December 31,	2011			2010			2009
Crude oil and natural gas properties owned by the Partnership:
Standardized measure at beginning of period	$	2,097,800		$	1,323,360		$	2,297,832
Extensions and discoveries
Net change in sales price, net of production costs	171,135			599,658			(240,994		)
Revisions of quantity estimates	(28,147		)	1,060,019			215,897
Net changes in estimated future development costs	—			—			(75,862		)
Changes in production timing rates	(92,615		)	172,591			(14,031		)
Accretion of discount	209,780			132,336			229,783
Sales net of production costs	(795,462		)	(1,190,164		)	(1,089,265		)
Sales of minerals in place	(907,271		)	—			—
Net increase (decrease)	(1,442,580		)	774,440			(974,472		)
Standardized measure at end of year	$	655,220		$	2,097,800		$	1,323,360