Attached files
file | filename |
---|---|
EX-31.1 - EXHIBIT 31.1 - Atlas America Public #15-2005 (A) L.P. | c04656exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - Atlas America Public #15-2005 (A) L.P. | c04656exv32w1.htm |
EX-31.2 - EXHIBIT 31.2 - Atlas America Public #15-2005 (A) L.P. | c04656exv31w2.htm |
EX-32.2 - EXHIBIT 32.2 - Atlas America Public #15-2005 (A) L.P. | c04656exv32w2.htm |
Table of Contents
United States
Securities and Exchange Commission
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 June 30, 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 000-51944
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
(Name of small business issuer in its charter)
Delaware | 20-3208344 | |
(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 (Address of principal executive offices) |
15108 (zip code) |
Issuers 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. Yes þ No o
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).
Yes o No o
Yes o No o
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 filer o | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) |
Smaller reporting company þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
(A Delaware Limited Partnership)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
(A Delaware Limited Partnership)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
PAGE | ||||||||
3 | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
7-17 | ||||||||
17-21 | ||||||||
21 | ||||||||
21 | ||||||||
21 | ||||||||
22 | ||||||||
CERTIFICATIONS |
||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
2
Table of Contents
PART 1. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
BALANCE SHEETS
BALANCE SHEETS
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | | $ | 161,500 | ||||
Accounts receivable-affiliate |
823,500 | 754,000 | ||||||
Short-term hedge receivable due from affiliate |
607,900 | 508,000 | ||||||
Total current assets |
1,431,400 | 1,423,500 | ||||||
Oil and gas properties, net |
15,933,500 | 17,108,600 | ||||||
Long-term hedge receivable due from affiliate |
789,000 | 417,700 | ||||||
$ | 18,153,900 | $ | 18,949,800 | |||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accrued liabilities |
$ | 58,200 | $ | 60,200 | ||||
Short-term hedge liability due to affiliate |
10,500 | 6,100 | ||||||
Total current liabilities |
68,700 | 66,300 | ||||||
Asset retirement obligation |
2,019,800 | 1,961,000 | ||||||
Long-term hedge liability due to affiliate |
251,700 | 64,400 | ||||||
Partners capital: |
||||||||
Managing general partner |
4,186,200 | 4,575,900 | ||||||
Limited partners (5,227.40 units) |
11,182,600 | 12,378,400 | ||||||
Accumulated other comprehensive income (loss) |
444,900 | (96,200 | ) | |||||
Total partners capital |
15,813,700 | 16,858,100 | ||||||
$ | 18,153,900 | $ | 18,949,800 | |||||
See accompanying notes to financial statements.
3
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENTS OF OPERATIONS
(Unaudited)
STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
REVENUES |
||||||||||||||||
Natural gas and oil |
$ | 627,700 | $ | 579,200 | $ | 1,501,100 | $ | 1,511,300 | ||||||||
Interest income |
| 100 | 100 | 300 | ||||||||||||
Total revenues |
627,700 | 579,300 | 1,501,200 | 1,511,600 | ||||||||||||
COSTS AND EXPENSES |
||||||||||||||||
Production |
339,800 | 349,500 | 679,300 | 737,700 | ||||||||||||
Depletion |
503,100 | 306,300 | 1,175,100 | 639,700 | ||||||||||||
Accretion of asset retirement obligation |
29,400 | 24,900 | 58,800 | 49,800 | ||||||||||||
General and administrative |
57,600 | 58,700 | 116,100 | 114,600 | ||||||||||||
Total expenses |
929,900 | 739,400 | 2,029,300 | 1,541,800 | ||||||||||||
Net loss |
$ | (302,200 | ) | $ | (160,100 | ) | $ | (528,100 | ) | $ | (30,200 | ) | ||||
Allocation of net (loss) earnings: |
||||||||||||||||
Managing general partner |
$ | (19,700 | ) | $ | (1,700 | ) | $ | 13,600 | $ | 103,200 | ||||||
Limited partners |
$ | (282,500 | ) | $ | (158,400 | ) | $ | (541,700 | ) | $ | (133,400 | ) | ||||
Net loss per limited partnership unit |
$ | (54 | ) | $ | (30 | ) | $ | (104 | ) | $ | (25 | ) | ||||
See accompanying notes to financial statements.
4
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENT OF CHANGES IN PARTNERS CAPITAL
FOR THE SIX MONTHS ENDED
June 30, 2010
(Unaudited)
STATEMENT OF CHANGES IN PARTNERS CAPITAL
FOR THE SIX MONTHS ENDED
June 30, 2010
(Unaudited)
Accumulated | ||||||||||||||||
Managing | Other | |||||||||||||||
General | Limited | Comprehensive | ||||||||||||||
Partner | Partners | (Loss) Income | Total | |||||||||||||
Balance at January 1, 2010 |
$ | 4,575,900 | $ | 12,378,400 | $ | (96,200 | ) | $ | 16,858,100 | |||||||
Participation in revenues and expenses: |
||||||||||||||||
Net production revenues |
275,300 | 546,500 | | 821,800 | ||||||||||||
Interest income |
| 100 | | 100 | ||||||||||||
Depletion |
(203,100 | ) | (972,000 | ) | | (1,175,100 | ) | |||||||||
Accretion of asset retirement obligation |
(19,700 | ) | (39,100 | ) | | (58,800 | ) | |||||||||
General and administrative |
(38,900 | ) | (77,200 | ) | | (116,100 | ) | |||||||||
Net earnings (loss) |
13,600 | (541,700 | ) | | (528,100 | ) | ||||||||||
Other comprehensive income |
| | 541,100 | 541,100 | ||||||||||||
Subordination |
(167,700 | ) | 167,700 | | | |||||||||||
Distributions to partners |
(235,600 | ) | (821,800 | ) | | (1,057,400 | ) | |||||||||
Balance at June 30, 2010 |
$ | 4,186,200 | $ | 11,182,600 | $ | 444,900 | $ | 15,813,700 | ||||||||
See accompanying notes to financial statements.
5
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENTS OF CASH FLOWS
(Unaudited)
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities: |
||||||||
Net loss |
$ | (528,100 | ) | $ | (30,200 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities: |
||||||||
Depletion |
1,175,100 | 639,700 | ||||||
Non-cash loss on derivative value |
261,600 | 901,300 | ||||||
Accretion of asset retirement obligation |
58,800 | 49,800 | ||||||
(Increase) decrease in accounts receivable-affiliate |
(69,500 | ) | 662,300 | |||||
Decrease in accrued liabilities |
(2,000 | ) | (4,800 | ) | ||||
Net cash provided by operating activities |
895,900 | 2,218,100 | ||||||
Cash flows from financing activities: |
||||||||
Distributions to partners |
(1,057,400 | ) | (2,404,100 | ) | ||||
Net cash used in financing activities |
(1,057,400 | ) | (2,404,100 | ) | ||||
Net decrease in cash and cash equivalents |
(161,500 | ) | (186,000 | ) | ||||
Cash and cash equivalents at beginning of period |
161,500 | 464,500 | ||||||
Cash and cash equivalents at end of period |
$ | | $ | 278,500 | ||||
See accompanying notes to financial statements.
6
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)
NOTE 1 BASIS OF PRESENTATION
Atlas America Public #15-2005 (A) L.P. (the Partnership) is a Delaware Limited Partnership
operates gas wells located primarily in western Pennsylvania and Tennessee. The Partnership
includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (MGP) and
Operator, and 1,637 Limited Partners. The MGP is a wholly owned subsidiary of Atlas Energy
Resources, LLC (ATN), an independent developer, and producer of natural gas and oil, with
operations in the Appalachian, Michigan and Illinois basin. ATN is a wholly-owned subsidiary of
Atlas Energy, Inc. (NASDAQ: ATLS).
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 for interim reporting. They do not include all disclosures normally made in financial
statements contained in Form 10-K. In managements opinion, all adjustments necessary for a fair
presentation of the Partnerships 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 Partnerships Annual Report on Form 10-K for the year ended December 31, 2009. The results of
operations for the three and six month periods ended June 30, 2010 may not necessarily be
indicative of the results of operations for the full year ending December 31, 2010.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the Partnerships 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 disclosure of
contingent assets and liabilities that exist at the date of the Partnerships financial statements,
as well as the reported amounts of revenue and costs and expenses during the reporting periods. The
Partnerships 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 months financial results. Management
believes that the operating results presented for the three and six months ended June 30, 2010 and
2009 represent actual results in all material respects (see Revenue Recognition accounting policy
for further description).
Fair Value of Financial Instruments
The carrying amounts of the Partnerships cash and receivables approximate fair values because
of the short maturities of these instruments.
7
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Properties
Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred.
Major renewals and improvements that extend the useful lives of property are capitalized. The
Partnership follows the successful efforts method of accounting for oil and gas producing
activities. Oil is converted to gas equivalent basis (Mcfe) at the rate of one barrel equals 6
Mcf.
The Partnerships depletion expense is determined on a field-by-field basis using the
units-of-production method. Depletion rates for lease, well, and related equipment costs are 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. Upon the
sale or retirement of a complete field of a proved property, the Partnership eliminates the cost
from the property accounts, and the resultant gain or loss is reclassified to the Partnerships
statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds
to accumulated depreciation and depletion within its 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 assets 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 Partnerships 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 Partnerships plans
to continue to produce 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.
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.
There were no impairments of proved oil and gas properties recorded by the Partnership for
the three and six months ended June 30, 2010 and 2009.
8
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
Revenue Recognition
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
Partnerships percentage ownership of working interest. Generally, the Partnerships 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 Partnerships records and management estimates of the related
commodity sales and transportation fees which are, in turn, based upon applicable product prices
(see Use of Estimates accounting policy for further description). The Partnership had unbilled
revenues at June 30, 2010 and December 31, 2009 of $485,700 and $534,000, respectively, which are
included in accounts receivable affiliate within the Partnerships balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net earnings (loss) and all other changes in the 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 of America, have
not been recognized in the calculation of net earnings (loss). These changes, other than net
earnings (loss), are referred to as other comprehensive income (loss) and for the Partnership
includes changes in the fair value of unsettled derivative contracts accounted for as cash flow
hedges. The following table sets forth the calculation of the Partnerships comprehensive income
(loss):
9
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ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Comprehensive Income (Loss) (Continued)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net loss |
$ | (302,200 | ) | $ | (160,100 | ) | $ | (528,100 | ) | $ | (30,200 | ) | ||||
Other comprehensive income (loss): |
||||||||||||||||
Unrealized holding gain (loss)
on hedging contracts |
590,800 | (41,000 | ) | 716,100 | (413,600 | ) | ||||||||||
Less: reclassification
adjustment for losses (gains)
realized in net earnings |
(49,700 | ) | 36,400 | (175,000 | ) | 142,500 | ||||||||||
Total other comprehensive income (loss) |
541,100 | (4,600 | ) | 541,100 | (271,100 | ) | ||||||||||
Comprehensive income (loss) |
$ | 238,900 | $ | (164,700 | ) | $ | 13,000 | $ | (301,300 | ) | ||||||
Recently Adopted Accounting Standards
In April 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2010-14, Accounting for Extractive Industries Oil & Gas: Amendments to Paragraph
932-10-S99-1 (Update 2010-14). Update 2010-14 provides amendments to add the SECs Regulation
S-X Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to
the Federal Securities Laws and the Energy Policy and Conservation Act of 1975 (S-X Rule 4-10)
to Accounting Standards Codification (ASC) Topic 932 Extractive Activities Oil and Gas. S-X
Rule 4-10 was included in the SECs Final Rule, Modernization of Oil, and Gas Reporting, which
became effective January 1, 2010. As Update 2010-14 only served to align the FASBs ASC Topic 932
with the SECs S-X Rule 4-10, the Partnerships adoption did not have a material impact on its
financial position, results of operations or related disclosures.
In February 2010, the FASB issued Accounting Standards Update 2010-09, Subsequent Events
(Topic 855): Amendments to Certain Recognition and Disclosure Requirements (Update 2010-09).
Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent
events have been evaluated in both issued and revised financial statements. Revised financial
statements include financial statements revised as a result of either correction of an error or
retrospective application of U.S. generally accepted accounting standards. The requirements of
Update 2010-09 were effective upon its issuance, February 24, 2010. The Partnership applied the
requirements of Update 2010-09 upon its adoption and it did not have an impact on its financial
position, results of operations or related disclosures.
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 entitys 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.
10
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ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Issued Accounting Standards
In March 2010, the FASB issued Accounting Standards Update 2010-11, Derivatives and Hedging
(Topic 815): Scope Exception Related to Embedded Credit Derivatives (Update 2010-11). Update
2010-11 provides clarification with regard to the type of embedded credit derivative that is exempt
from embedded derivative bifurcation requirements. Specifically, only one form of embedded credit
derivative qualifies for the exemption one that is related only to the subordination of one
financial instrument to another. As a result, entities that have contracts containing an embedded
credit derivative feature in a form other than such subordination may need to separately account
for the embedded credit derivative feature. The requirements of Update 2010-11 are effective at the
start of a reporting entitys first fiscal year beginning after June 15, 2010 (July 1, 2010 for the
Partnership). The Partnership will apply the requirements of Update 2010-11 upon its adoption on
July 1, 2010 and does not expect it to have a material impact on its financial position, results of
operations or related disclosures.
NOTE 3 OIL AND GAS PROPERTIES
The following is a summary of oil and gas properties:
June 30, | December 31, | |||||||
2010 | 2009 | |||||||
Natural gas and oil properties: |
||||||||
Proved properties: |
||||||||
Leasehold interests |
$ | 1,526,600 | $ | 1,526,600 | ||||
Wells and related equipment |
64,512,600 | 64,512,600 | ||||||
66,039,200 | 66,039,200 | |||||||
Accumulated depletion |
(50,105,700 | ) | (48,930,600 | ) | ||||
$ | 15,933,500 | $ | 17,108,600 | |||||
NOTE 4 ASSET RETIREMENT OBLIGATIONS
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil
and gas wells and related facilities. It also recognizes a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as part of the carrying amount of the long-lived
asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the MGPs 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 credit-adjusted 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. Except for its oil and gas properties, the Partnership has determined
that there are no other material retirement obligations associated with tangible long-lived assets.
11
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 4 ASSET RETIREMENT OBLIGATIONS (Continued)
A reconciliation of the Partnerships liability for well plugging and abandonment costs for
the periods indicated is as follows:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Asset retirement obligation at beginning of
period |
$ | 1,990,400 | $ | 1,684,300 | $ | 1,961,000 | $ | 1,659,400 | ||||||||
Accretion expense |
29,400 | 24,900 | 58,800 | 49,800 | ||||||||||||
Asset retirement obligation at end of period |
$ | 2,019,800 | $ | 1,709,200 | $ | 2,019,800 | $ | 1,709,200 | ||||||||
NOTE 5 DERIVATIVE INSTRUMENTS
The MGP on behalf of the Partnership uses a number of different derivative instruments,
principally swaps, collars, and options, in connection with its commodity price risk management
activities. The MGP enters into financial instruments to hedge its forecasted natural gas and crude
oil sales 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 MGP
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.
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 assess, 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 MGP 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 within gain (loss) on mark-to-market
derivatives in the Partnerships 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 reclassifies the portion relating to commodity
derivatives to gas and oil production revenues for the Partnerships derivatives within the
Partnerships 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.
Derivatives are recorded on the Partnerships balance sheet as assets or liabilities at fair
value. The Partnership reflected net derivative assets on its balance sheets of $1,134,700 at June
30, 2010, however unrealized gain of $689,800 recognized in income results in a net accumulated
other comprehensive income balance of $444,900. The unrealized gain of $689,800 is comprised of
$684,700 and $5,100 from 2008 and 2006 impairments respectively. Of the remaining $444,900 net
unrealized gain in accumulated other comprehensive income at June 30, 2010, if the fair values of
the instruments remain at current market values, the Partnership will reclassify $262,600 of gains
to the Partnerships statements of operations over the next twelve month period as these contracts
expire. Aggregate gains of $182,300 will be reclassified to the Partnerships statements of
operations in later periods as these remaining contracts expire. Actual amounts that will be
reclassified will vary as a result of future price changes.
12
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ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 5 DERIVATIVE INSTRUMENTS (Continued)
The following table summarizes the fair value of the Partnerships derivative instruments as
of June 30, 2010 and December 31, 2009, as well as the gain or loss recognized in the statements of
operations for effective derivative instruments for the three and six months ended June 30, 2010
and 2009:
Fair Value of Derivative Instruments:
Asset Derivatives | Liability Derivatives | |||||||||||||||||||||||
Derivatives in | Fair Value | Fair Value | ||||||||||||||||||||||
Cash Flow | Balance Sheet | June 30, | December 31, | Balance Sheet | June 30, | December 31, | ||||||||||||||||||
Hedging Relationships | Location | 2010 | 2009 | Location | 2010 | 2009 | ||||||||||||||||||
Commodity contracts: |
Current assets | $ | 607,900 | $ | 508,000 | Current liabilities | $ | (10,500 | ) | $ | (6,100 | ) | ||||||||||||
Long-term assets | 789,000 | 417,700 | Long-term liabilities | (251,700 | ) | (64,400 | ) | |||||||||||||||||
Total derivatives |
$ | 1,396,900 | $ | 925,700 | $ | (262,200 | ) | $ | (70,500 | ) | ||||||||||||||
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 | June 30, | June 30, | OCI into Income | June 30, | June 30, | |||||||||||||||
Hedging Relationship | 2010 | 2009 | (Effective Portion) | 2010 | 2009 | |||||||||||||||
Commodity contracts |
$ | 590,800 | $ | (41,000 | ) | Natural gas and oil revenue | $ | 49,700 | $ | (36,400 | ) | |||||||||
Gain/(Loss) | Gain/(Loss) | |||||||||||||||||||
Recognized in OCI on Derivative | Reclassified from OCI into Income | |||||||||||||||||||
(Effective Portion) | Location of Gain/(Loss) | (Effective Portion) | ||||||||||||||||||
Derivatives in | Six Months Ended | Reclassified from Accumulated | Six Months Ended | |||||||||||||||||
Cash Flow | June 30, | June 30, | OCI into Income | June 30, | June 30, | |||||||||||||||
Hedging Relationship | 2010 | 2009 | (Effective Portion) | 2010 | 2009 | |||||||||||||||
Commodity contracts |
$ | 716,100 | $ | (413,600 | ) | Natural gas and oil revenue | $ | 175,000 | $ | (142,500 | ) | |||||||||
The MGP enters into natural gas and crude oil future option contracts and collar
contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas
and oil prices. At any point in time, such contracts may include regulated New York Mercantile
Exchange (NYMEX) futures and 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.
13
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ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 5 DERIVATIVE INSTRUMENTS (Continued)
Natural Gas Fixed Price Swaps
Production | Average | |||||||||||||||
Period Ending | Volumes | Fixed Price | Fair Value | |||||||||||||
December 31, | (MMbtu)(1) | (per MMbtu)(1) | Asset(2) | |||||||||||||
2010 |
139,600 | $ | 7.238 | $ | 336,200 | |||||||||||
2011 |
190,600 | 6.839 | 284,300 | |||||||||||||
2012 |
127,800 | 7.165 | 186,200 | |||||||||||||
2013 |
72,000 | 7.011 | 77,400 | |||||||||||||
2014 |
| | | |||||||||||||
$ | 884,100 | |||||||||||||||
Natural Gas Costless Collars
Production | Average | |||||||||||||||
Period Ending | Option | Volumes | Floor & Cap | Fair Value | ||||||||||||
December 31, | Type | (MMbtu)(1) | (per MMbtu)(1) | Asset (Liability)(2) | ||||||||||||
2010 |
Puts purchased | 18,800 | $ | 6.123 | $ | 31,700 | ||||||||||
2010 |
Calls sold | 18,800 | 7.327 | (2,700 | ) | |||||||||||
2011 |
Puts purchased | 88,000 | 6.435 | 141,300 | ||||||||||||
2011 |
Calls sold | 88,000 | 7.545 | (26,000 | ) | |||||||||||
2012 |
Puts purchased | 79,400 | 6.012 | 116,900 | ||||||||||||
2012 |
Calls sold | 79,400 | 7.181 | (65,700 | ) | |||||||||||
2013 |
Puts purchased | 92,700 | 6.010 | 154,500 | ||||||||||||
2013 |
Calls sold | 92,700 | 7.173 | (112,300 | ) | |||||||||||
2014 |
Puts purchased | 32,200 | 5.860 | 54,000 | ||||||||||||
2014 |
Calls sold | 32,200 | 6.961 | (50,700 | ) | |||||||||||
$ | 241,000 | |||||||||||||||
Crude Oil Fixed Price Swaps
Production | Average | |||||||||||||||
Period Ending | Volumes | Fixed Price | Fair Value | |||||||||||||
December 31, | (Bbl)(1) | (per Bbl)(1) | Asset(3) | |||||||||||||
2010 |
200 | $ | 97.123 | $ | 3,300 | |||||||||||
2011 |
200 | 88.304 | 2,200 | |||||||||||||
2012 |
200 | 87.901 | 1,200 | |||||||||||||
2013 |
100 | 88.211 | 300 | |||||||||||||
2014 |
| | | |||||||||||||
$ | 7,000 | |||||||||||||||
14
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ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 5 DERIVATIVE INSTRUMENTS (Continued)
Crude Oil Costless Collars
Production | Average | |||||||||||||
Period Ending | Option | Volumes | Floor & Cap | Fair Value | ||||||||||
December 31, | Type | (Bbl)(1) | (per Bbl)(1) | Asset (Liability)(3) | ||||||||||
2010 |
Puts purchased | 100 | $ | 85.000 | $ | 1,000 | ||||||||
2010 |
Calls sold | 100 | 112.350 | (50 | ) | |||||||||
2011 |
Puts purchased | 200 | 77.381 | 1,500 | ||||||||||
2011 |
Calls sold | 200 | 101.642 | (600 | ) | |||||||||
2012 |
Puts purchased | 100 | 76.756 | 1,400 | ||||||||||
2012 |
Calls sold | 100 | 102.181 | (850 | ) | |||||||||
2013 |
Puts purchased | 50 | 76.757 | 500 | ||||||||||
2013 |
Calls sold | 50 | 103.103 | (300 | ) | |||||||||
2014 |
Puts purchased | | | | ||||||||||
2014 |
Calls sold | | | | ||||||||||
$ | 2,600 | |||||||||||||
Total Net Aset | $ | 1,134,700 | ||||||||||||
(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 Unadjusted quoted prices in active markets for identical, unrestricted 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.
Level 3 Unobservable inputs that reflect the entitys own assumptions about the assumption
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.
15
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
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 Partnerships commodity 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 on a Non-Recurring 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:
amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and
estimated inflation rates (see Note 4).
NOTE 7 CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
| Administrative costs which are included in general and administrative expenses in the
Partnerships statements of operations are payable at $75 per well per month.
Administrative costs incurred for the three and six months ended June 30, 2010 were
$37,400 and $75,400, respectively. Administrative costs incurred for the three and six
months ended June 30, 2009 were $39,500 and $79,100, respectively. |
||
| Monthly well supervision fees which are included in production expenses in the
Partnerships 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 and six months ended June 30, 2010 were $147,700 and $297,800,
respectively. Well supervision fees incurred for the three and six months ended June 30,
2009 were $156,300 and $312,600, respectively. |
||
| Transportation fees which are included in production expenses in the Partnerships
statements of operations are generally payable at 13% of the natural gas sales price.
Transportation fees incurred for the three and six months ended June 30, 2010 were
$96,900 and $215,500, respectively. Transportation fees incurred for the three and six
months ended June 30, 2009 were $125,100 and $288,700, respectively. |
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
Partnerships 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 (August 2006) and expiring 60 months from that date. For the six months ended
June 30, 2010, the MGP was required to subordinate $167,700 of its net production of $335,300.
Therefore, MGP capital was decreased and the limited partners capital was increased by $167,700 as shown on
the Statement of Changes in Partners Capital for the six months ended June 30, 2010.
16
Table of Contents
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2010
(Unaudited)
NOTE 8 COMMITMENTS AND CONTINGENCIES
Legal Proceedings
The Managing General Partner is not aware of any legal proceedings filed against the
Partnership.
The Partnerships MGP is a party to various routine legal proceedings arising out of the
ordinary course of its business. Management believes that none of these actions, individually or in
the aggregate, will have a material adverse effect on the Partnerships financial condition or
results of operations.
ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (UNAUDITED) |
Forward-Looking Statements
When used in this Form 10-Q, the words believes, anticipates, expects and similar
expressions are intended to identify forward-looking statements. There are risks and uncertainties
that 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 this Form 10-Q or to reflect the occurrence of unanticipated events.
BUSINESS OVERVIEW
We are a Delaware Limited Partnership which operates gas wells located primarily in western
Pennsylvania and Tennessee. Our Partnership includes Atlas Resources, LLC of Pittsburgh,
Pennsylvania, as Managing General Partner (MGP) and operator, and 1,637 Limited Partners. The MGP
is a wholly-owned subsidiary of Atlas Energy Resources, LLC (ATN), and independent developer and
producer of natural gas and oil, with operations in the Appalachian, Michigan and Illinois Basin.
ATN is a wholly-owned subsidiary of Atlas Energy, Inc, (NASDAQ: ATLS).
Our wells are currently producing natural gas and to a lesser extent, oil which are our only
products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream,
LLCs gas gathering system, a joint venture between Atlas
Energys 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.
17
Table of Contents
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 | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Production revenues (in thousands): |
||||||||||||||||
Gas |
$ | 606 | $ | 575 | $ | 1,455 | $ | 1,490 | ||||||||
Oil |
22 | 4 | 46 | 21 | ||||||||||||
Total |
$ | 628 | $ | 579 | $ | 1,501 | $ | 1,511 | ||||||||
Production volumes: |
||||||||||||||||
Gas (mcf/day) (1) |
1,151 | 1,440 | 1,354 | 1,508 | ||||||||||||
Oil (bbls/day) (1) |
4 | 3 | 4 | 4 | ||||||||||||
Total (mcfe/day) (1) |
1,175 | 1,458 | 1,378 | 1,532 | ||||||||||||
Average sales prices: (2) |
||||||||||||||||
Gas (per mcf) (1) (3) |
$ | 7.36 | $ | 7.90 | $ | 6.97 | $ | 8.70 | ||||||||
Oil (per bbl) (1) (4) |
$ | 76.95 | $ | 41.74 | $ | 73.41 | $ | 52.50 | ||||||||
Average production costs: |
||||||||||||||||
As a percent of revenues |
54 | % | 60 | % | 45 | % | 49 | % | ||||||||
Per mcfe (1) |
$ | 3.18 | $ | 2.63 | $ | 2.72 | $ | 2.66 | ||||||||
Depletion per mcfe |
$ | 4.71 | $ | 2.31 | $ | 4.71 | $ | 2.31 |
(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 $165,100 and $459,900 for the three months
ended June 30, 2010 and 2009, respectively. Previously recognized derivative gains were $252,600 and $883,700 for the six months ended June 30, 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 $5,100 and $8,400 for the three months
ended June 30, 2010 and 2009, respectively. Previously recognized derivative gains were $9,000 and $17,600 for the six months ended June 30, 2010 and 2009, respectively. The derivative gains are included in other comprehensive income and resulted from prior period impairment charges. |
18
Table of Contents
Natural Gas Revenues. Our natural gas revenues were $605,400 and $575,200 for the three
months ended June 30, 2010 and 2009, respectively, an increase of $30,200 (5%). The $30,200
increase in natural gas revenues for the three months ended June 30, 2010 as compared to the prior
year similar period was attributable to a $145,500 increase in natural gas sales prices after the
effect financial hedges, which are driven by market conditions, partially offset by a $115,300
decrease in production volumes. Our production volumes decreased to 1,151 mcf per day for the three
months ended June 30, 2010 from 1,440 mcf per day for the three months ended June 30, 2009, a
decrease of 289 mcf per day (20%). The overall decrease in natural
gas production volumes for the three months ended June 30, 2010
resulted primarily from the normal decline inherent in the life of a
well.
Our natural gas revenues were $1,455,200 and $1,490,200 for the six months ended June 30, 2010
and 2009, respectively, a decrease of $35,000 (2%). The $35,000 decrease in natural gas revenues
for the six months ended June 30, 2010 as compared to the prior year similar period was
attributable to a $151,800 decrease in production volumes, partially offset by a $116,800 increase
in natural gas sales prices after the effect of financial hedges, which are driven by market
conditions. Our production volumes decreased to 1,354 mcf per day for the six months ended June 30,
2010 from 1,508 mcf per day for the six months ended June 30, 2009, a decrease of 154 mcf per day
(10%). The overall decrease in natural
gas production volumes for the six months ended June 30, 2010
resulted primarily from the normal decline inherent in the life of a
well.
Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells
have limited oil production. Our oil revenues were $22,300 and $4,000 for the three months ended
June 30, 2010 and 2009, respectively, an increase of $18,300. The $18,300 increase in oil revenues
for the three months ended June 30, 2010 as compared to the prior year similar period was
attributable to a $17,500 increase in oil prices after the effect of financial hedges which are
driven by market conditions and a $800 increase in production volumes. Our production volumes
increased to 4 bbls per day for the three months ended June 30, 2010 from 3 bbls per day for the
three months ended June 30, 2009, an increase of 1 bbl per day (33%).
Our oil revenues were $45,900 and $21,100 for the six months ended June 30, 2010 and 2009,
respectively, an increase of $24,800 (118%). The $24,800 increase in oil revenues for the six
months ended June 30, 2010 as compared to the prior year similar period was attributable to a
$24,500 increase in oil prices after the effect of financial hedges and a $300 increase in
production volumes.
Expenses. Production expenses were $339,800 and $349,500 for the three months ended June 30,
2010 and 2009, respectively, a decrease of $9,700 (3%). Production expenses were $679,300 and
$737,700 for the six months ended June 30, 2010 and 2009, respectively, a decrease of $58,400
(8%).These decreases for the three and six months ended June 30, 2010 was mostly due to lower
transportation and supervision fees.
Depletion of oil and gas properties as a percentage of oil and gas revenues were 80% and 53%
for the three months ended June 30, 2010 and 2009, respectively; and 78% and 42% for the six months
ended June 30, 2010 and 2009, respectively. These percentage changes are directly attributable to
changes in revenues, oil and gas reserve quantities, product prices and production volumes and
changes in the depletable cost basis of oil and gas properties.
General and administrative expenses for the three months ended June 30, 2010 and 2009 were
$57,600 and $58,700, respectively, a decrease of $1,100 (2%). For the six months ended June 30,
2010 and 2009 these expenses were $116,100 and $114,600, respectively, an increase of $1,500 (1%).
These expenses include third-party costs for services as well as the monthly administrative fees
charged by our MGP. The decrease for the three months ended June 30, 2010 was primarily due to
lower third-party costs as compared to the prior year similar period. The increase for the six
months ended June 30, 2010, was primarily due to higher third-party costs as compared to the prior
year similar period.
Liquidity and Capital Resources
Cash provided by operating activities decreased $1,322,200 in the six months ended June 30,
2010 to $895,900 as compared to $2,218,100 for the six months ended June 30, 2009. This decrease
was due to a decrease of a net non-cash loss on derivative values of $639,700 and the change in
accounts receivable affiliate of $731,800, partially offset with an increase in net earnings before
depletion and accretion of $46,500 and the change in accrued liabilities increased operating cash
flows by $2,800, for the six months ended June 30, 2010 compared to the six months ended June 30,
2009.
19
Table of Contents
Cash used in financing activities decreased $1,346,700 during the six months ended June 30,
2010 to $1,057,400 from $2,404,100 for the six months ended June 30, 2009. This decrease was due to
a decrease in cash distributions.
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.
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 (August 2006) and expiring 60 months from that date. For the six months ended
June 30, 2010, the MGP was required to subordinate $167,700 of its net production of $335,300.
Therefore, MGP capital was decreased and the limited partners capital was increased by $167,700 as shown on
the Statement of Changes in Partners Capital for the six months ended June 30, 2010.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires making estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of actual revenue and expenses during
the reporting period. Although we base our estimates on historical experience and various other
assumptions that we believe to be reasonable under the circumstances, actual results may differ
from the estimates on which our financial statements are prepared at any given point of time.
Changes in these estimates could materially affect our financial position, results of operations or
cash flows. Significant items that are subject to such estimates and assumptions include revenue
and expense accruals, depletion, asset impairment, fair value of derivative instruments, and the
probability of forecasted transactions. A discussion of our significant accounting policies we have
adopted and followed in the preparation of our financial statements
is included within our Annual
Report on Form 10-K for the year ended December 31, 2009 and in Note 2 under Item 1, Financial
Statements included in this report, and there have been no material changes to these policies
through June 30, 2010.
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which
requires us 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 Unadjusted quoted prices in active markets for identical, unrestricted 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.
Level 3 Unobservable inputs that reflect the entitys own assumptions about the assumption
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.
20
Table of Contents
We use a fair value methodology to value the assets and liabilities for our outstanding
derivative contracts. Our commodity hedges are calculated 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.
Liabilities that are required to be measured at fair value on a nonrecurring basis include our
asset retirement obligations (AROs) that are defined as Level 3. Estimates of the fair value of
AROs are based on discounted cash flows using numerous estimates, assumptions, and judgments
regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.
ITEM 4. | 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 SECs rules and forms, and that
such information is accumulated and communicated to our management, including our Chief Executive
Officer 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 and with the participation of our management, including our Chief
Executive Officer 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 Chief Executive Officer and Chief Financial Officer
concluded that, as of June 30, 2010, our disclosure controls, and procedures were effective at the
reasonable assurance level.
There have been no changes in our internal control over financial reporting during our most
recent fiscal quarter that have materially affected, or are reasonably likely to materially affect,
our internal control over financial reporting.
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
MGPs financial condition or results of operation.
ITEM 6. | EXHIBITS |
EXHIBIT INDEX
Exhibit No. | Description | |
4.0
|
Amended and Restated Certificate and Agreement of Limited Partnership for Public #15-2005 (A) L.P. (1) | |
10.1
|
Drilling and Operating Agreement for Atlas America Public #15-2005 (A) L.P. (1) | |
31.1
|
Rule 13a-14(a)/15d-14(a) Certification. | |
31.2
|
Rule 13a-14(a)/15d-14(a) Certification. | |
32.1
|
Section 1350 Certification. | |
32.2
|
Section 1350 Certification. |
(1) | Filed on August 9, 2005 in the Form S-1 Registration Statement dated August 9, 2005, File No. 000-51944 |
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Table of Contents
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the
registrant caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
Atlas America Public #15-2005
(A) L.P. Atlas Resources, LLC, Managing General Partner |
||||
Date: August 16, 2010 | By: | /s/ FREDDIE M. KOTEK | ||
Freddie M. Kotek | ||||
Chairman of the Board of Directors Chief Executive Officer and President |
||||
Date: August 16, 2010 | By: | /s/ MATTHEW A. JONES | ||
Matthew A. Jones | ||||
Chief Financial Officer | ||||
Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the
Exchange Act by Non-reporting Issuers
Exchange Act by Non-reporting Issuers
An annual report will be furnished to security holders subsequent to the filing of this report.
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