Atlas America Public #15-2006 10-Q 2010 Q1 Quarterly report

United States
Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission file number 000-52168

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

(Name of small business issuer in its charter)

Delaware	20-3208390
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Westpointe Corporate Center One
1550 Coraopolis Heights Rd. 2nd Floor
Moon Township, PA	15108
(Address of principal executive offices)	(zip code)

Issuer’s telephone number, including area code:(412) 262-2830

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso Noþ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filero Accelerated filero Non-accelerated filero Smaller reporting companyþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Transitional Small Business Disclosure Format (check one): Yeso Noþ

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.
(A Delaware Limited Partnership)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q

	PAGE
PART I. FINANCIAL INFORMATION
Item 1: Financial Statements
Balance Sheets as of March 31, 2010 and December 31, 2009		3
Statements of Operations for the Three Months ended March 31, 2010 and 2009		4
Statement of Changes in Partners’ Capital for the Three Months ended March 31, 2010		5
Statements of Cash Flows for the Three Months ended March 31, 2010 and 2009		6
Notes to Financial Statements		7-16
Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations		16-19
Item 4: Controls and Procedures		19
PART II. OTHER INFORMATION
Item 1: Legal Proceedings		20
Item 6: Exhibits		20
SIGNATURES		21
CERTIFICATIONS
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

2

ATLAS AMERICA PUBLIC #15-2006(B) L.P.

BALANCE SHEETS

	March 31,		December 31,
	2010		2009
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	794,400	$	728,600
Accounts receivable-affiliate		2,376,600		2,881,200
Short-term hedge receivable due from affiliate		3,082,900		1,896,500
Total current assets		6,253,900		5,506,300
Oil and gas properties, net		44,831,700		46,184,800
Long-term hedge receivable due from affiliate		2,795,500		1,560,900
	$	53,881,100	$	53,252,000
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accrued liabilities	$	102,000	$	111,500
Short-term hedge liability due to affiliate		18,300		22,900
Total current liabilities		120,300		134,400
Asset retirement obligation		5,227,000		5,149,700
Long-term hedge liability due to affiliate		571,500		236,400
Partners’ capital:
Managing general partner		11,482,800		12,081,600
Limited partners (14,772.60 units)		33,253,100		34,752,000
Accumulated other comprehensive income		3,226,400		897,900
Total partners’ capital		47,962,300		47,731,500
	$	53,881,100	$	53,252,000

The accompanying notes are an integral part of these financial statements.

3

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENTS OF NET OPERATIONS

(Unaudited)

	Three Months Ended
	March 31,
	2010			2009
REVENUES
Natural gas and oil	$	2,807,200		$	3,558,500
Interest income		200			500
Total revenues		2,807,400			3,559,000
COSTS AND EXPENSES
Production		1,036,600			1,379,200
Depletion		1,361,200			1,157,500
Accretion of asset retirement obligation		77,300			66,900
General and administrative		125,700			126,100
Total expenses		2,600,800			2,729,700
Net earnings	$	206,600		$	829,300
Allocation of net (loss) earnings:
Managing general partner	$	275,500		$	471,100
Limited partners	$	(68,900	)	$	358,200
Net (loss) earnings per limited partnership unit	$	(5	)	$	24

The accompanying notes are an integral part of these financial statements.

4

ATLAS AMERICA PUBLIC #15-2006 (B) L.P.

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE THREE MONTHS ENDED

March 31, 2010

(Unaudited)

							Accumulated
	Managing						Other
	General			Limited			Comprehensive
	Partner			Partners			Income		Total
Balance at January 1, 2010	$	12,081,600		$	34,752,000		$	897,900	$	47,731,500
Participation in revenues and expenses:
Net production revenues		588,700			1,181,900			—		1,770,600
Interest income		100			100			—		200
Depletion		(245,800	)		(1,115,400	)		—		(1,361,200	)
General and administrative		(41,800	)		(83,900	)		—		(125,700	)
Accretion of asset retirement obligation		(25,700	)		(51,600	)		—		(77,300	)
Net earnings (loss)		275,500			(68,900	)		—		206,600
Other comprehensive income		—			—			2,328,500		2,328,500
Subordination		(378,500	)		378,500			—		—
Asset contributions		9,200			—			—		9,200
Distributions to partners		(505,000	)		(1,808,500	)		—		(2,313,500	)
Balance at March 31, 2010	$	11,482,800		$	33,253,100		$	3,226,400	$	47,962,300

The accompanying notes are an integral part of these financial statements.

5

ATLAS AMERICA PUBLIC #15-2006(B) L.P.

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended
	March 31,
	2010			2009
Cash flows from operating activities:
Net earnings	$	206,600		$	829,300
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion		1,361,200			1,157,500
Non-cash loss on derivative value		238,000			1,077,900
Accretion of asset retirement obligation		77,300			66,900
Decrease in accounts receivable — affiliate		504,600			1,302,700
Decrease in accrued liabilities		(9,500	)		(3,500	)
Net cash provided by operating activities		2,378,200			4,430,800
Cash flows from investing activities:
Sale of equipment		1,100			136,800
Net cash provided by investing activities		1,100			136,800
Cash flows from financing activities:
Distributions to partners		(2,313,500	)		(4,584,500	)
Net cash used in financing activities		(2,313,500	)		(4,584,500	)
Net (decrease) increase in cash and cash equivalents		65,800			(16,900	)
Cash and cash equivalents at beginning of period		728,600			1,405,200
Cash and cash equivalents at end of period	$	794,400		$	1,388,300
Supplemental schedule of non-cash investing and financing activities:
Assets contributed by managing general partner:
Tangible equipment	$	—		$	83,200
Intangible drilling costs		9,200			25,100
	$	9,200		$	108,300

The accompanying notes are an integral part of these financial statements.

6

ATLAS AMERICA PUBLIC #15-2006(B) L.P.

NOTES TO FINANCIAL STATEMENTS

March 31, 2010

(Unaudited)

NOTE 1 — DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America Public #15-2006 (B) L.P. (the “Partnership”) is a Delaware Limited Partnership which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and Operator, and 4,132 subscribers to units as Limited Partners. The Partnership was formed on May 9, 2006 to drill and operate gas wells located primarily in western Pennsylvania, Ohio, and Tennessee.

In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc, (NASDAQ: ATLS). Atlas Resources, LLC serves as the Partnership’s MGP.

The accompanying financial statements, which are unaudited except that the balance sheet at December 31, 2009, is derived from audited financial statements, are presented in accordance with the requirements of Form 10-Q and accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made in financial statements contained in Form 10-K. In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto presented in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the three months ended March 31, 2010 may not necessarily be indicative of the results of operation for the year ended December 31, 2010.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

In addition to matters discussed further in this note, the Partnership’s significant accounting policies are detailed in its audited financial statements and notes thereto in the Partnership’s annual report on Form 10-K for the year ended December 31, 2009 filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates

Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments and the probability of forecasted transactions. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the three months ended March 31, 2010 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).

7

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Accounts Receivable and Allowance for Possible Losses

In evaluating the need for an allowance for possible losses, the Partnership’s MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At March 31, 2010 and December 31, 2009, the Partnership’s MGP’s credit evaluation indicated that the Partnership has no need for an allowance for possible losses.

Revenue Recognition

The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest. Generally, the MGP’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership records and estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled revenues at March 31, 2010 and December 31, 2009 of $1,699,600 and $2,105,100, respectively, which are included in accounts receivable-affiliate within the Partnership’s Balance Sheets.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.

8

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-Lived Assets (Continued)

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.

Working Interest

The Partnership agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions, (“the working interest”). The MGP is also provided an additional working interest of 7% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined, and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

Oil and Gas Properties

The Partnership follows the successful-efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is determined on a field-by-field basis using the units-of-production method for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of the property are capitalized. The Partnership is required to consider estimated salvage value in the calculation of depletion. Oil and gas properties consist of the following at the dates indicated:

	March 31,			December 31,
	2010			2009
Natural gas and oil properties:
Proved properties:
Leasehold interests	$	4,196,500		$	4,196,500
Wells and related equipment		183,422,500			183,414,400
		187,619,000			187,610,900
Accumulated depletion		(142,787,300	)		(141,426,100	)
	$	44,831,700		$	46,184,800

9

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Oil and Gas Properties (Continued)

The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows. There was no impairment charges recognized for the three month periods ending March 31, 2010 and 2009.

Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the Statement of Operations.

Recently Adopted Accounting Standards

In January 2010, the FASB issued Accounting Standards Update 2010-02, “Fair Value Measurement and Disclosures (Topic (820) — Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Partnership). The Partnership applied the requirements of Update 2010-06 upon its adoption on January 1, 2010, and it did not have a material impact on its financial position, results of operations or related disclosures.

NOTE 3 — TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES

The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under its Partnership agreement:

• Administrative costs which are included in general and administrative expenses in the Partnership’s Statements of Operations are payable at $75 per well per month. Administrative costs incurred for the three months ended March 31, 2010 and 2009 were $103,900 and $106,100, respectively.

• Monthly well supervision fees which are included in production expenses in the Partnership’s Statements of Operations are payable at $296 per well per month in 2010 and 2009 respectively, for operating and maintaining the wells. Well supervision fees incurred for the three months ended March 31, 2010 and 2009 were $410,400 and $419,400, respectively.

• Transportation fees which are included in production expenses in the Partnership’s Statements of Operations are generally at 13% of the natural gas sales price. Transportation fees incurred for the three months ended March 31, 2010 and 2009 were $351,200 and $529,100, respectively.

• Assets contributed from the MGP which are disclosed on the Partnership’s Statements of Cash Flows as a non-cash activity of the three months ended March 31, 2010 and 2009 were $9,200 and $108,300, respectively.

10

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 3 — TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES (Continued)

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership’s Balance Sheets represents the net production revenues due from the MGP.

Subordination by Managing General Partner

Under the terms of the partnership agreement, the MGP may be required to subordinate up to 50% of its share of production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (March 2007) and expiring 60 months from that date. For the three months ended March 31, 2010, the MGP was required to subordinate $378,500 of its net production of $757,000. Therefore MGP capital was decreased and the limited partners capital was increased by $378,500 as shown on the Statement of Changes in Partners’ Capital for the three months ended March 31, 2010.

NOTE 4 — COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) includes net income (loss) and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net loss, are referred to as “other comprehensive income (loss)” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedge. A reconciliation of the Partnership’s comprehensive income (loss) for the periods indicated is as follows:

	Three Months Ended
	March 31,
	2010			2009
Net earnings	$	206,600		$	829,300
Other comprehensive income (loss):
Unrealized holding gains (losses) on hedging contracts		2,923,700			(1,084,100	)
Less: reclassification adjustment for (gains) losses realized in net earnings		(595,200	)		63,300
Total other comprehensive income (loss)		2,328,500			(1,020,800	)
Comprehensive income (loss)	$	2,535,100		$	(191,500	)

NOTE 5 — DERIVATIVE INSTRUMENTS

The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge the Partnership’s forecasted natural gas, and crude oil against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, and crude oil is sold. Under swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, and crude oil at a fixed price for the relevant contract period.

11

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately in the Partnership’s Statements of Operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners’ capital as accumulated other comprehensive income and will reclassify commodity derivatives to gas and oil production revenues in the Partnership’s Statements of Operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its Statements of Operations as they occur. The following table summarizes the fair value of derivative instruments as of March 31, 2010 and December 31, 2009, as well as the gain or loss on the derivative instruments as of March 31, 2010 and 2009, respectively.

Fair Value of Derivative Instruments:

	Asset Derivatives					Liability Derivatives
Derivatives in		Fair Value					Fair Value
Cash Flow	Balance Sheet	March 31,		December 31,		Balance Sheet	March 31,			December 31,
Hedging Relationships	Location	2010		2009		Location	2010			2009
Commodity contracts:	Current assets	$	3,082,900	$	1,896,500	Current liabilities	$	(18,300	)	$	(22,900	)
	Long-term assets		2,795,500		1,560,900	Long-term liabilities		(571,500	)		(236,400	)
Total derivatives		$	5,878,400	$	3,457,400		$	(589,800	)	$	(259,300	)

Effects of Derivative Instruments on Statements of Operations:

	Gain/(Loss)						Gain/(Loss)
	Recognized in OCI on Derivative						Reclassified from OCI into Income
	(Effective Portion)					Location of Gain/(Loss)	(Effective Portion)
Derivatives in	Three Months Ended					Reclassified from Accumulated	Three Months Ended
Cash Flow	March 31,		March 31,			OCI into Income	March 31,		March 31,
Hedging Relationship	2010		2009			(Effective Portion)	2010		2009
Commodity contracts	$	2,923,700	$	(1,084,100	)	Natural gas and oil revenue	$	595,200	$	(63,300	)

At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.

12

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

At March 31, 2010, the Partnership reflected a net hedge asset on our Balance Sheets of $5,288,600, however unrealized gains of $2,062,200 recognized in income results in a net accumulated other comprehensive income balance of $3,226,400. The unrealized gain of $2,062,200 is from 2008 impairments. Of the remaining $3,226,400 net unrealized gain in accumulated other comprehensive income at March 31, 2010, if the fair values of the instruments remain at current market values, the Partnership will reclassify $2,102,400 of net gains to its Statements of Operations over the next twelve month period as these contracts settle, and $1,124,000 of net gains in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge contract is open and may increase or decrease until settlement of the contract.

As of March 31, 2010, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:

Natural Gas Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(MMbtu)(1)		(per MMbtu)(1)		Asset(2)
2010		796,200	$	7.35	$	2,436,600
2011		593,900		6.69		1,001,000
2012		428,000		6.85		638,200
2013		267,600		6.82		236,800
					$	4,312,600

Natural Gas Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(MMbtu)(1)		(per MMbtu)(1)		Asset(2)
2010	Puts purchased		55,900	$	7.84	$	231,200
2010	Calls sold		55,900		9.01		—
2011	Puts purchased		299,200		6.20		457,700
2011	Calls sold		299,200		7.28		—
2012	Puts purchased		187,800		6.22		160,800
2012	Calls sold		187,800		7.31		—
2013	Puts purchased		227,300		6.23		116,900
2013	Calls sold		227,300		7.39		—
						$	966,600

13

ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 5 — DERIVATIVE INSTRUMENTS (Continued)

Crude Oil Fixed Price Swaps

Production			Average
Period Ending	Volumes		Fixed Price		Fair Value
December 31,	(Bbl)(1)		(per Bbl)(1)		Asset(3)
2010		500	$	97.22	$	5,900
2011		500		77.46		1,000
2012		300		76.86		400
2013		100		77.36		100
					$	7,400

Crude Oil Costless Collars

Production				Average
Period Ending	Option	Volumes		Floor & Cap		Fair Value
December 31,	Type	(Bbl)(1)		(per Bbl)(1)		Asset(3)
2010	Puts purchased		300	$	85.00	$	1,400
2010	Calls sold		300		112.55		—
2011	Puts purchased		300		67.22		300
2011	Calls sold		300		89.44		—
2012	Puts purchased		200		65.51		200
2012	Calls sold		200		91.45		—
2013	Puts purchased		100		65.36		100
2013	Calls sold		100		93.44		—
						$	2,000
					Total Net Asset	$	5,288,600

(1)	MMBTU represents million British Thermal Units. Bbl represents barrels.
(2)	Fair value based on forward NYMEX natural gas prices as applicable.
(3)	Fair value based on forward WTI crude oil prices as applicable.

NOTE 6 — FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 —Quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

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ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 6 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 5). The Partnership’s derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Assets and Liabilities measured at fair value at March 31, 2010 and December 31, 2009 were as follows.

	March 31, 2010				December 31, 2009
	Level 2		Total		Level 2		Total
Commodity-based derivatives	$	5,288,600	$	5,288,600	$	3,198,100	$	3,198,100
Total	$	5,288,600	$	5,288,600	$	3,198,100	$	3,198,100

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The Partnership estimates the fair value of asset retirement obligations, using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amount and timing of settlements; the risk-free rate of the Partnership; and estimated inflation rates (see Note 7).

The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.

NOTE 7 — ASSET RETIREMENT OBLIGATION

The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells. The associated asset retirement costs are capitalized as part of oil and gas properties. The Partnership also considers the estimated salvage value in the calculation of depletion.

The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed risk free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations.

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ATLAS AMERICA PUBLIC #15-2006(B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2010
(Unaudited)

NOTE 7 — ASSET RETIREMENT OBLIGATION (Continued)

A reconciliation of the Partnership’s liability for plugging and abandonment costs for the periods indicated is as follows:

	Three Months Ended
	March 31,
	2010		2009
Asset retirement obligation at beginning of period	$	5,149,700	$	4,458,800
Accretion expense		77,300		66,900
Asset retirement obligation at end of period	$	5,227,000	$	4,525,700

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (UNAUDITED)

Forward-Looking Statements

When used in thisForm 10-Q, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These risks and uncertainties could cause actual results to differ materially from the results stated or implied in this document. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly release the results of any revisions to forward-looking statements which we may make to reflect events or circumstances after the date of thisForm 10-Q or to reflect the occurrence of unanticipated events.

Management’s Discussion and Analysis should be read in conjunction with our Financial Statements and the Notes to our Financial Statements.

General

We were formed as a Delaware limited partnership on May 9, 2006, with Atlas Resources, LLC as our Managing General Partner, or MGP, to drill natural gas development wells. Atlas Resources, Inc. was merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas America, Inc. Atlas Resources, LLC now serves as our MGP.

In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc, (NASDAQ: ATLS). Atlas Resources, LLC serves as the Partnership’s MGP.

Our wells are currently producing natural gas and oil which are our only products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream, LLC’s gas gathering system, a newly formed joint-venture between Atlas Energy, Inc.’s affiliate Atlas Pipeline Partners L.P. (NYSE: APL) and The Williams Companies Inc. (NYSE: WMB). We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.

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Results of Operations

The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

	Three Months Ended
	March 31,
	2010			2009
Production revenues (in thousands):
Gas	$	2,743		$	3,489
Oil		64			70
Total	$	2,807		$	3,559
Production volumes:
Gas (mcf/day)(1)		5,175			5,466
Oil (bbls/day)(1)		11			14
Total (mcfe/day)(1)		5,241			5,550
Average sales prices: (2)
Gas (per mcf)(1) (3)	$	6.38		$	9.24
Oil (per bbl)(1) (4)	$	71.63		$	68.20
Average production costs:
As a percent of revenues		37	%		39	%
Per mcfe(1)	$	2.20		$	2.76
Depletion per mcfe	$	2.89		$	2.32

(1)	“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent, and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(2)	Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.
(3)	Average gas prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $229,800 and $1,058,500 for the three months ended March 31, 2010 and 2009, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.
(4)	Average oil prices are calculated by including in total revenue derivative gains previously recognized into income and dividing by the total volume for the period. Previously recognized derivative gains were $8,200 and $19,400 for the three months ended March 31, 2010 and 2009, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges.

Natural Gas Revenues.Our natural gas revenues were $2,743,500 and $3,488,900 for the three months ended March 31, 2010 and 2009, respectively, a decrease of $745,400 (21%). The $745,400 decrease in natural gas revenues for the three months ended March 31, 2010 as compared to the prior year period was attributable to a $185,900 decrease in production volumes and a $559,500 decrease in our natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 5,175 mcf per day for the three months ended March 31, 2010 from 5,466 mcf per day for the three months ended March 31, 2009, a decrease of 291 mcf per day (5%). The overall decrease in natural gas production volumes for the three months ended March 31, 2010 resulted primarily from the normal decline inherit in the life of a well.

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Oil Revenues.We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $63,700 and $69,600 for the three months ended March 31, 2010 and 2009, respectively, a decrease of $5,900 (8%). The $5,900 decrease in oil revenues for the three months ended March 31, 2010 as compared to the prior year similar period was attributable to a $16,000 decrease in production volumes, partially offset by a $10,100 increase in oil prices after the effect of financial hedges. Our production volumes decreased to 11 bbls per day for the three months ended March 31, 2010 from 14 bbls per day for the three months ended March 31, 2009, a decrease of 3 bbls per day (21%).

Expenses.Production expenses were $1,036,600 and $1,379,200 for the three months ended March 31, 2010 and 2009, respectively, a decrease of $342,600 (25%). This decrease was primarily attributable to a decrease in transportation fees, which are affected by a decrease in production volumes.

Depletion of oil and gas properties as a percentage of oil and gas revenues were 48% and 33% for the three months ended March 31, 2010 and 2009, respectively. These percentage changes are directly attributable to revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.

General and administrative expenses for the three months ended March 31, 2010 and 2009, were $125,700 and $126,100, respectively, a decrease of $400. These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP.

Liquidity and Capital Resources

Cash provided by operating activities decreased $2,052,600 in the three months ended March 31, 2010 to $2,378,200 as compared to $4,430,800 for the three months ended March 31, 2009. This decrease was due to a decrease in net earnings before depletion and accretion of $408,600 and the change in the net non-cash loss on derivative values of $839,900. In addition, the change in accounts receivable — affiliate decreased operating cash flows by $798,100 in the three months ended March 31, 2010 compared to the three months ended March 31, 2009.

Cash provided by investing activities was $1,100 and $136,800 for the three months ended March 31, 2010 and 2009, respectively. This was entirely due to proceeds from a sale of equipment.

Cash used in financing activities decreased $2,271,000 to $2,313,500 during the three months ended March 31, 2010, from $4,584,500 during the three months ended March 31, 2009. This decrease was due to lower distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

We believe that our future cash flows from operations and amounts available from borrowings from our MGP or its affiliates, if any, will be adequate to fund our operations.

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Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. On an on-going basis, we evaluate our estimates, including those related to our asset retirement obligations, depletion and certain accrued receivables and liabilities. We base our estimates on historical experience and on various other assumptions that we believe reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. A discussion of our significant accounting policies we have adopted and followed in the preparation of our financial statements is included within “Notes to Financial Statements” in Part I, Item 1, “Financial Statements” in this quarterly report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

Subordination by Managing General Partner

Under the terms of the Partnership agreement, the MGP may be required to subordinate up to 50% of its share of production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (March 2007) and expiring 60 months from that date. For the three months ended March 31, 2010, the MGP was required to subordinate $378,500 of its net production of $757,000. Therefore MGP capital was decreased and the limited partners capital was increased by $378,500 as shown on the Statement of Changes in Partners’ Capital for the three months ended March 31, 2010.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, at March 31, 2010, our disclosure controls and procedures were effective at the reasonable assurance level.

There have been no changes in the Partnership’s internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially effect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Managing General Partner is not aware of any legal proceedings filed against the Partnership.

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

ITEM 6. EXHIBITS

EXHIBIT INDEX

Exhibit No.		Description
	4.0	Amended and Restated Certificate and Agreement of Limited Partnership for Public #15-2006 (B) L.P.(1)
	10.1	Drilling and Operating Agreement for Atlas America Public #15-2006 (B) L.P.(1)
	31.1	Certification Pursuant to Rule 13a-14/15(d)-14
	31.2	Certification Pursuant to Rule 13a-14/15(d)-14
	32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(1) Filed on April 17, 2006 in the Form S-1 Registration Statement dated April 17, 2006, File No. 000-52168

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SIGNATURES

Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Atlas America Public #15-2006 (B) L.P.

	Atlas Resources, LLC, Managing General Partner
Date: May 17, 2010	By:	/s/ Freddie M. Kotek
		Freddie M. Kotek, Chairman of the Board of Directors,
		Chief Executive Officer and President

In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date: May 17, 2010	By:	/s/ Freddie M. KotekFreddie M. Kotek, Chairman of the Board of Directors,
		Chief Executive Officer and President
Date: May 17, 2010	By:	/s/ Matthew A. JonesMatthew A. Jones, Chief Financial Officer
Date: May 17, 2010	By:	/s/ Sean P. McGrathSean P. McGrath, Chief Accounting Officer

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