e10vq
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
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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)
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Delaware
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20-3208344 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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Westpointe Corporate Center One |
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1550 Coraopolis Heights Rd. 2nd Floor |
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Moon Township, PA
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15108 |
(Address of principal executive offices)
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(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
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):
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Large accelerated filer o
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Accelerated filer o
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Non-accelerated filer o
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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
Transitional Small Business Disclosure Format (check one): Yes o No þ
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
(A Delaware Limited Partnership)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
2
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
BALANCE SHEETS
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March 31, |
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December 31, |
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2011 |
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2010 |
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(Unaudited) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
61,700 |
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$ |
115,500 |
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Accounts receivable affiliate |
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687,500 |
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471,400 |
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Short-term hedge receivable due from affiliate |
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466,800 |
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Total current assets |
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749,200 |
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1,053,700 |
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Oil and gas properties, net |
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6,790,400 |
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6,913,400 |
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Long-term hedge receivable due from affiliate |
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456,300 |
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Long-term receivable due from affiliate |
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331,400 |
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$ |
7,871,000 |
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$ |
8,423,400 |
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LIABILITIES AND PARTNERS CAPITAL |
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Current liabilities: |
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Accrued liabilities |
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$ |
13,900 |
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$ |
13,500 |
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Short-term hedge liability due to affiliate |
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4,600 |
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Total current liabilities |
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13,900 |
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18,100 |
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Asset retirement obligation |
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2,675,400 |
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2,635,900 |
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Long-term hedge liability due to affiliate |
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80,800 |
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Partners capital: |
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Managing general partner |
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2,056,300 |
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2,392,500 |
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Limited partners (5,227.40 units) |
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2,848,600 |
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3,207,800 |
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Accumulated other comprehensive income |
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276,800 |
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88,300 |
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Total partners capital |
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5,181,700 |
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5,688,600 |
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$ |
7,871,000 |
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$ |
8,423,400 |
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See accompanying notes to financial statements.
3
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENTS OF OPERATIONS
(Unaudited)
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Three Months Ended |
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March 31, |
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2011 |
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2010 |
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REVENUES |
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Natural gas and oil |
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$ |
298,500 |
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$ |
873,400 |
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Interest income |
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100 |
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Total revenues |
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298,500 |
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873,500 |
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COSTS AND EXPENSES |
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Production |
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261,500 |
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339,500 |
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Depletion |
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123,000 |
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672,000 |
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Accretion of asset retirement obligation |
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39,500 |
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29,400 |
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General and administrative |
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53,500 |
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58,500 |
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Total costs and expenses |
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477,500 |
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1,099,400 |
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Net loss |
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$ |
(179,000 |
) |
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$ |
(225,900 |
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Allocation of net (loss) income: |
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Managing general partner |
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$ |
(49,700 |
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$ |
33,300 |
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Limited partners |
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$ |
(129,300 |
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$ |
(259,200 |
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Net loss per limited partnership unit |
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$ |
(25 |
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$ |
(50 |
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See accompanying notes to financial statements.
4
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENT OF CHANGES IN PARTNERS CAPITAL
FOR THE THREE MONTHS ENDED
March 31, 2011
(Unaudited)
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Accumulated |
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Managing |
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Other |
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General |
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Limited |
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Comprehensive |
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Partner |
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Partners |
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Income |
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Total |
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Balance at January 1, 2011 |
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$ |
2,392,500 |
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$ |
3,207,800 |
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$ |
88,300 |
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$ |
5,688,600 |
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Participation in revenues and expenses: |
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Net production revenues |
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3,100 |
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33,900 |
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37,000 |
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Depletion |
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(21,700 |
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(101,300 |
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(123,000 |
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Accretion of asset retirement obligation |
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(13,200 |
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(26,300 |
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(39,500 |
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General and administrative |
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(17,900 |
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(35,600 |
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(53,500 |
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Net loss |
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(49,700 |
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(129,300 |
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(179,000 |
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Other comprehensive income |
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188,500 |
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188,500 |
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Subordination |
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(27,300 |
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27,300 |
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Distributions to partners |
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(259,200 |
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(257,200 |
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(516,400 |
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Balance at March 31, 2011 |
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$ |
2,056,300 |
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$ |
2,848,600 |
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$ |
276,800 |
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$ |
5,181,700 |
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See accompanying notes to financial statements.
5
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
STATEMENTS OF CASH FLOWS
(Unaudited)
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Three Months Ended |
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March 31, |
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2011 |
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2010 |
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Cash flows from operating activities: |
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Net loss |
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$ |
(179,000 |
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$ |
(225,900 |
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Adjustments to reconcile net loss to net cash provided by operating activities: |
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Depletion |
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123,000 |
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672,000 |
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Non cash loss on derivative value |
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130,100 |
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91,500 |
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Accretion of asset retirement obligation |
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39,500 |
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29,400 |
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Decrease (increase) in accounts receivable-affiliate |
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141,100 |
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(13,800 |
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Increase (decrease) in accrued liabilities |
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400 |
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(8,300 |
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Net cash provided by operating activities |
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255,100 |
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544,900 |
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Cash flows from financing activities: |
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Distributions to partners |
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(308,900 |
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(517,500 |
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Net cash used in financing activities |
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(308,900 |
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(517,500 |
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Net (decrease) increase in cash and cash equivalents |
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(53,800 |
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27,400 |
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Cash and cash equivalents at beginning of period |
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115,500 |
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161,500 |
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Cash and cash equivalents at end of period |
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$ |
61,700 |
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$ |
188,900 |
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Supplemental Schedule of non-cash operating and financing activities: |
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Distribution to managing general partner |
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$ |
207,500 |
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$ |
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See accompanying notes to financial statements.
6
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS
March 31, 2011
(Unaudited)
NOTE 1 DESCRIPTION OF BUSINESS
Atlas America Public 15-2005 (A) L.P. (the Partnership) is a Delaware limited partnership,
formed on July 25, 2005 with Atlas Resources, LLC serving as its Managing General Partner and
operator (Atlas Resources or MGP). Atlas Resources is an indirect subsidiary of Atlas Energy,
L.P., formerly Atlas Pipeline Holdings, L.P. (Atlas Energy) (NYSE: ATLS). On February 17, 2011,
Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general
partner of Atlas Pipeline Partners, L.P. (APL) (NYSE: APL), completed an acquisition of assets
from Atlas Energy, Inc., which included its investment partnership business; its oil and gas
exploration, development and production activities conducted in Tennessee, Indiana, and Colorado,
certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania
and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P.
and related entities.
Atlas Resources focus is on the development and/or production of natural gas and oil in the
Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America.
Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment
partnerships, in which it co-invests to finance the exploitation and development of its acreage.
Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to
manage its assets and raise capital.
The accompanying financial statements, which are unaudited except that the balance sheets at
December 31, 2010, 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 the Form 10-K. 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, 2010. The results of
operations for the three months ended March 31, 2011 may not necessarily be indicative of the
results of operations for the year ended December 31, 2011.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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.
In addition to matters discussed further in this note, the Partnerships significant
accounting policies are detailed in its audited financial statements and notes thereto in the
Partnerships Form 10-K for the year ended December 31, 2010 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 Partnerships financial statements, as well as the
reported amounts of revenues 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.
7
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Use of Estimates (Continued)
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 months ended March 31, 2011 and 2010
represent actual results in all material respects (see Revenue Recognition accounting policy for
further description).
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit
evaluations of its customers and adjusts credit limits based upon payment history and the
customers 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, 2011 and
December 31, 2010, the Partnerships MGPs credit evaluation indicated that the Partnership had no
need for an allowance for possible losses.
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.
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March 31, |
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December 31, |
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2011 |
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2010 |
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Proved properties: |
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Leasehold interests |
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$ |
1,526,600 |
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$ |
1,526,600 |
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Wells and related equipment |
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65,069,800 |
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65,069,800 |
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66,596,400 |
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66,596,400 |
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Accumulated depletion |
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(59,806,000 |
) |
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(59,683,000 |
) |
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$ |
6,790,400 |
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$ |
6,913,400 |
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8
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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,
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 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.
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.
There was no impairment charge recognized during the three months ended March 31, 2011. During the
year ended December 31, 2010, the Partnership recognized an impairment charge of $8,286,900, net of
an offsetting gain in accumulated other comprehensive income of $291,400.
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 (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.
9
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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 March 31, 2011 and December 31, 2010 of $226,800 and $312,500, respectively, which are
included in accounts receivable affiliate within the Partnerships balance sheets.
Recently Adopted Accounting Standards
As of the date of this filing, there are no newly issued accounting standards which impacted
the presentation of the attached financial statements that have not already been adopted.
NOTE 3 ASSET RETIREMENT OBLIGATION
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.
10
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 3 ASSET RETIREMENT OBLIGATION (Continued)
A reconciliation of the Partnerships liability for plugging and abandonment costs for the
periods indicated is as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Asset retirement obligation at beginning of period |
|
$ |
2,635,900 |
|
|
$ |
1,961,000 |
|
Accretion expense |
|
|
39,500 |
|
|
|
29,400 |
|
|
|
|
|
|
|
|
Asset retirement obligation at end of period |
|
$ |
2,675,400 |
|
|
$ |
1,990,400 |
|
|
|
|
|
|
|
|
NOTE 4 COMPREHENSIVE INCOME
Comprehensive income includes net 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 of America, have not been recognized
in the calculation of net loss. These changes, other than net loss, are referred to as other
comprehensive income and, for the Partnership, include changes in the fair value of unsettled
derivative contracts accounted for as cash flow hedges. A reconciliation of the Partnerships
comprehensive income for the periods indicated is as follows:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2011 |
|
|
2010 |
|
Net loss |
|
$ |
(179,000 |
) |
|
$ |
(225,900 |
) |
Other comprehensive income: |
|
|
|
|
|
|
|
|
Net unrealized gain |
|
|
230,600 |
|
|
|
772,000 |
|
Less: reclassification adjustment for gain realized in net loss |
|
|
(42,100 |
) |
|
|
(125,300 |
) |
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
188,500 |
|
|
|
646,700 |
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
9,500 |
|
|
$ |
420,800 |
|
|
|
|
|
|
|
|
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 Partnerships 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 #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 5 DERIVATIVE INSTRUMENTS (Continued)
Historically, the MGP has entered into natural gas and crude oil future option contracts and
collar contracts on behalf of the Partnership 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.
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 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.
Prior to the acquisition on February 17, 2011 (the Transferred Business), ATLS monetized its
derivative instruments related to the Transferred Business. The monetized proceeds relate to
instruments that were originally put into place to hedge future natural gas and oil production of
the Transferred Business, including production generated through its Drilling Partnerships. At
March 31, 2011, the Partnership recorded a net receivable from the monetized derivative instruments
of $357,200 in accounts receivable-affiliate and $331,400 in long-term receivable-affiliate with
the corresponding net unrealized gains in accumulated other comprehensive income on the
Partnerships balance sheets, which will be allocated to natural gas and oil production revenue
over the period of the original instruments contracts. As a result of the early settlement of
natural gas and oil derivative positions and the unrealized gains recognized in income in prior
periods due to natural gas and oil property impairments, the Partnership recorded a net deferred
gain on its balance sheets in other comprehensive income of $276,800 as of March 31, 2011.
Unrealized gains, net of the MGPs interest, previously recognized into income as a result of prior
period impairments were $110,500 and $301,300 for the year ended December 31, 2010 and prior
periods, respectively. The MGPs portion of the unrealized gains were written off as a result of
the Transferred Business. For the three months ended March 31, 2011, the Partnership reclassified
$207,500 of unrealized gains previously recognized into income from prior period impairments
related to the MGP from a hedge receivable due from affiliate as a distribution to the MGP. As such
$207,500 was recorded as a distribution to partners on the statement of changes in partners
capital. During the period, $27,700 of monetized proceeds were recorded by the Partnership and
allocated to the limited partners only. Of the remaining $276,800 of net unrealized gain in
accumulated other comprehensive income, the Partnership will reclassify $134,600 of net gains to
the Partnerships statements of operations over the next twelve month period and the remaining
$142,200 in later periods.
12
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 5 DERIVATIVE INSTRUMENTS (Continued)
The following table summarizes the fair value of the Partnerships derivative instruments as
of December 31, 2010, as well as the gain or loss recognized in the statements of operations for
the three months ended March 31, 2011 and 2010:
Fair Value of Derivative Instruments:
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
Derivatives in Cash Flow Hedging Relationships |
|
Balance Sheet Location |
|
December 31, 2010 |
|
|
|
|
|
|
|
|
Derivative Commodity Contracts |
|
Current Assets |
|
$ |
466,800 |
|
|
|
Long-Term Assets |
|
|
456,300 |
|
|
|
|
|
|
|
|
|
|
|
|
923,100 |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
(4,600 |
) |
|
|
Long-term liabilities |
|
|
(80,800 |
) |
|
|
|
|
|
|
|
|
|
|
|
(85,400 |
) |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
837,700 |
|
|
|
|
|
|
|
Effects of Derivative Instruments on Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain |
|
|
Location of Gain |
|
Gain |
|
|
|
Recognized in OCI on Derivative |
|
|
Reclassified from Accumulated |
|
Reclassified from OCI into Net Loss |
|
|
|
Three Months Ended |
|
|
OCI into Income |
|
Three Months Ended |
|
Cash Flow |
|
March 31, |
|
|
March 31, |
|
|
|
|
March 31, |
|
|
March 31, |
|
Hedging Relationship |
|
2011 |
|
|
2010 |
|
|
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
$ |
230,600 |
|
|
$ |
772,000 |
|
|
Natural gas and oil revenue |
|
$ |
42,100 |
|
|
$ |
125,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
Level 3 Unobservable inputs that reflect the entities 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 used a fair value methodology to value the assets and liabilities for its
outstanding derivative contracts (see Note 5). The Partnerships commodity derivative contracts
were 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.
13
ATLAS AMERICA PUBLIC #15-2005 (A) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
March 31, 2011
(Unaudited)
NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
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 3).
NOTE 7 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
Partnerships statements of operations are payable at $75 per well per month.
Administrative costs incurred for the three months ended March 31, 2011 and 2010 were
$35,400 and $38,000, 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 for
operating and maintaining the wells. Well supervision fees incurred for the three months
ended March 31, 2011 and 2010 were $139,700 and $150,100, 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 months ended March 31, 2011 and 2010 were
$52,900 and $118,600, 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 net production revenues of the Partnership to provide a distribution to the limited
partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a
cumulative basis, in each of the first five years of Partnership operations, commencing with the
first distribution of net revenues to the limited partners (August 2006). For the three months
ended March 31, 2011, the MGP was required to subordinate $27,300. Therefore, MGP capital was
decreased and the limited partners capital was increased by $27,300 as shown on the statement of
changes in partners capital for the three months ended March 31, 2011.
14
|
|
|
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. 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 this Form 10-Q or to reflect the occurrence of unanticipated events.
Managements Discussion and Analysis should be read in conjunction with our Financial
Statements and the Notes to our Financial Statements.
General
General. We are a Delaware limited partnership, formed on July 25, 2005 with Atlas Resources,
LLC serving as our Managing General Partner and operator (Atlas Resources or MGP). Atlas
Resources is an indirect subsidiary of Atlas Energy, L.P., formerly Atlas Pipeline Holdings, L.P.
(Atlas Energy) (NYSE: ATLS). On February 17, 2011, Atlas Energy, a then-majority owned subsidiary
of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P. (APL)
(NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its
investment partnership business; its oil and gas exploration, development and production activities
conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and
Ohio, and certain well interests in Pennsylvania and Michigan; and its ownership and management of
investments in Lightfoot Capital Partners, L.P. and related entities.
Atlas Resources focus is on the development and/or production of natural gas and oil in the
Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America.
Atlas Resources is also a leading sponsor of and manages tax-advantaged direct investment
partnerships, in which it co-invests to finance the exploitation and development of its acreage.
Atlas Energy Resource Services, Inc. provides Atlas Resources with the personnel necessary to
manage its assets and raise capital.
We have drilled and currently operate wells located in Pennsylvania and Tennessee. We have no
employees and rely on our MGP for management, which in turn, relies on its parent company, Atlas
Energy Holdings Operating Company, LLC for administrative services.
15
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 |
|
|
|
2011 |
|
|
2010 |
|
Production revenues (in thousands): |
|
|
|
|
|
|
|
|
Gas |
|
$ |
283 |
|
|
$ |
850 |
|
Oil |
|
|
15 |
|
|
|
23 |
|
|
|
|
|
|
|
|
Total |
|
$ |
298 |
|
|
$ |
873 |
|
|
|
|
|
|
|
|
|
|
Production volumes: |
|
|
|
|
|
|
|
|
Gas (mcf/day) (1) |
|
|
788 |
|
|
|
1,560 |
|
Oil (bbls/day) (1) |
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
|
Total (mcfe/day) (1) |
|
|
800 |
|
|
|
1,584 |
|
|
|
|
|
|
|
|
|
|
Average sales prices: (2) |
|
|
|
|
|
|
|
|
Gas (per mcf) (1) (3) |
|
$ |
5.83 |
|
|
$ |
6.68 |
|
Oil (per bbl) (1) (4) |
|
$ |
87.82 |
|
|
$ |
70.20 |
|
|
|
|
|
|
|
|
|
|
Average production costs: |
|
|
|
|
|
|
|
|
As a percent of revenues |
|
|
88 |
% |
|
|
39 |
% |
Per mcfe (1) |
|
$ |
3.63 |
|
|
$ |
2.38 |
|
|
|
|
|
|
|
|
|
|
Depletion per mcfe |
|
$ |
1.71 |
|
|
$ |
4.71 |
|
|
|
|
(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 $130,200 and $87,500 for the three months
ended March 31, 2011 and 2010, respectively. The derivative gains are included in other
comprehensive (loss) 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 a derivative loss of $100 and a gain of $3,900 for the three
months ended March 31, 2011 and 2010, respectively. The derivative gains are included
in other comprehensive (loss) income and resulted from prior period impairment charges. |
Natural Gas Revenues. Our natural gas revenues were $283,300 and $849,800 for the three
months ended March 31, 2011 and 2010, respectively, a decrease of $566,500 (67%). The $566,500
decrease in natural gas revenues for the three months ended March 31, 2011 as compared to the prior
year period was attributable to a $420,400 decrease in production volumes and a $146,100 decrease
in our natural gas sales prices after the effect of financial hedges, which were driven by market
conditions. Our production volumes decreased to 788 mcf per day for the three months ended March
31, 2011 from 1,560 mcf per day for the three months ended March 31, 2010, a decrease of 772 mcf
per day (49%). The overall decrease in natural gas production volumes for the three months ended
March 31, 2011 resulted primarily from the normal decline inherit in the life of a well.
16
Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells
have limited oil production. Our oil revenues were $15,200 and $23,600 for the three months ended
March 31, 2011 and 2010, respectively, a decrease of $8,400 (36%). The $8,400 decrease in oil
revenues for the three months ended March 31, 2011 as compared to the prior year similar period was
attributable a $13,200 decrease in production volumes, partially offset by a $4,800 increase in oil
prices after the effect of financial hedges. Our production volumes decreased to 2 bbls per day for
the three months ended March 31, 2011 from 4 bbls per day for the three months ended March 31,
2010, a decrease of 2 bbls per day (50%).
Costs and Expenses. Production expenses were $261,500 and $339,500 for the three months ended
March 31, 2011 and 2010, respectively, a decrease of $78,000 (23%). The decrease for the three
months ended March 31, 2011 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 41%
and 77% for the three months ended March 31, 2011 and 2010, respectively. These percentage changes
are directly attributable to changes in 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, 2011 and 2010, were
$53,500 and $58,500, respectively, a decrease of $5,000 (9%). These expenses include third-party
costs for services as well as the monthly administrative fees charged by our MGP, and vary from
year to year due to the timing and billing of the costs and services provided to us.
Liquidity and Capital Resources
Cash provided by operating activities decreased $289,800 in the three months ended March 31,
2011 to $255,100 as compared to $544,900 for the three months ended March 31, 2010. This decrease
was due to a decrease in net earnings before depletion and accretion of $492,000, partially offset
by an increase of a net non-cash loss on derivative values of $38,600. In addition, the change in
accounts receivable-affiliate increased operating cash flows by $154,900 and an increase in the
change in accrued liabilities affiliate of $8,700 for the three months ended March 31, 2011
compared to the three months ended March 31, 2010.
Cash used in financing activities decreased $208,600 during the three months ended March 31,
2011 to $308,900 from $517,500 for the three months ended March 31, 2010. 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.
17
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, 2010.
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 net production revenues of the Partnership to provide a distribution to the limited
partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a
cumulative basis, in each of the first five years of Partnership operations, commencing with the
first distribution of net revenues to the limited partners (August 2006). For the three months
ended March 31, 2011, the MGP was required to subordinate $27,300. Therefore, MGP capital was
decreased and the limited partners capital was increased by $27,300 as shown on the statement of
changes in partners capital for the three months ended March 31, 2011.
|
|
|
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 SECs 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, 2011, our disclosure controls and
procedures were effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in the Partnerships 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.
18
PART II OTHER INFORMATION
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ITEM 1. |
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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 operations.
EXHIBIT INDEX
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Exhibit No. |
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Description |
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4.0 |
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Amended and Restated Certificate and Agreement of Limited Partnership for Public #15-2005 (A) L.P. (1) |
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10.1 |
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Drilling and Operating Agreement for Atlas America Public #15-2005 (A) L.P. (1) |
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31.1 |
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Certification Pursuant to Rule 13a-14/15(d)-14 |
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31.2 |
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Certification Pursuant to Rule 13a-14/15(d)-14 |
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32.1 |
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Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 |
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32.2 |
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Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley |
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Act of 2002 |
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(1) |
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Filed on August 9, 2005 in the Form S-1A Registration Statement dated August 9, 2005, File No. 000-51944 |
19
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 #15-2005 (A) L.P.
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Atlas Resources, LLC, Managing General Partner
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Date: May 13, 2011 |
By: |
/s/ Freddie M. Kotek
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Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President |
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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.
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Date: May 13, 2011 |
By: |
/s/ Jeffrey C. Simmons
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Jeffrey C. Simmons, Executive Vice President, Operations |
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Date: May 13, 2011 |
By: |
/s/ Sean P. McGrath
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Sean P. McGrath, Chief Financial Officer |
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20