NOTE 11 — SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserve Information. The preparation of the Partnership's natural gas and oil reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas Resources Public #18-2009 (B) L.P annual Form 10-K for the years ended December 31, 2012 and 2011 (see Note 2). For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States, primarily in Michigan, Indiana, Ohio, Pennsylvania and Tennessee. The independent reserves engineer's evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. The Partnership's internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership's senior engineering staff and management, with final approval by the Partnership's Executive Vice President.

The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2012, and 2011 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2012 and 2011 and, including adjustments related to regional price differentials and energy content.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of oil and gas reserves included within the Partnership or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.

Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):

	Gas (Mcf)	Oil (Bbls)	Liquid (Bbls)

Balance, December 31, 2010	30,908,800	48,300	85,100
Revisions⁽¹⁾	(2,369,800)	(7,700)	5,100
Production	(3,120,000)	(6,500)	(8,500)

Balance, December 31, 2011	25,419,000	34,100	81,700
Revisions ^{(1) (2)}	(4,711,400)	(11,200)	(20,500)
Production	(2,241,700)	(2,400)	(3,600)

Balance, December 31, 2012	18,465,900	20,500	57,600

(1) The change in the 2011 natural gas reserves was due to actual production being less than engineering forecasts. The change in 2012 and 2011 oil reserves is due to changes in engineering forecasts after considering the impact of actual gas production.

(2) The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.

Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:


	Years Ended December 31,
	2012	2011
Natural gas and oil properties:
Leasehold interest	$ 1,055,800	$ 1,055,800
Wells and related equipment	132,283,700	132,257,800

Accumulated depletion, accretion and impairment	(106,738,200)	(48,919,500)

Net capitalized costs	$ 26,601,300	$ 84,394,100

Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership's oil and gas producing activities during the periods indicated were as follows:


	Years Ended December 31,
	2012	2011
Revenues	$ 8,179,700	$ 17,972,300
Production costs	(3,087,300)	(4,287,300)
Depletion and amortization	(7,784,600)	(10,042,400)
Long-lived asset impairment	(48,973,500)	(3,221,300)

	$ (51,665,700)	$ 421,300

The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership's proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2012 and 2011, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:


	Years Ended December 31,
	2012	2011

Future cash inflows	$ 57,590,400	$ 118,761,300
Future production costs	(26,403,200)	(45,507,500)
Future development costs	(769,700)	—
Future net cash flows	30,417,500	73,253,800
Less 10% annual discount for estimated timing of cash flows	(14,918,600)	(36,907,600)
Standardized measure of discounted future net cash flows	$ 15,498,900	$ 36,346,200