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EXCEL - IDEA: XBRL DOCUMENT - ATLAS AMERICA PUBLIC #10 LTD. | Financial_Report.xls |
EX-31.1 - EXHIBIT 31.1 - ATLAS AMERICA PUBLIC #10 LTD. | c20885exv31w1.htm |
EX-32.2 - EXHIBIT 32.2 - ATLAS AMERICA PUBLIC #10 LTD. | c20885exv32w2.htm |
EX-31.2 - EXHIBIT 31.2 - ATLAS AMERICA PUBLIC #10 LTD. | c20885exv31w2.htm |
EX-32.1 - EXHIBIT 32.1 - ATLAS AMERICA PUBLIC #10 LTD. | c20885exv32w1.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, 2011
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 000-49777
ATLAS AMERICA PUBLIC #10 Ltd.
(Name of small business issuer in its charter)
Pennsylvania | 25-1891457 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
Westpointe Corporate Center One | ||
1550 Coraopolis Heights Rd. 2nd Floor | ||
Moon Township, PA | 15108 | |
(Address of principal executive offices) | (zip code) |
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
þ 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 | 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 #10 LTD.
(A PENNSYLVANIA LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
(A PENNSYLVANIA LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
PAGE | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
7-15 | ||||||||
15-18 | ||||||||
19 | ||||||||
19 | ||||||||
19 | ||||||||
20 | ||||||||
CERTIFICATIONS |
||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
2
Table of Contents
ATLAS AMERICA PUBLIC #10 LTD.
BALANCE SHEETS
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 59,800 | $ | 53,300 | ||||
Accounts receivable-affiliate |
520,100 | 342,400 | ||||||
Short-term hedge receivable due from affiliate |
| 335,100 | ||||||
Total current assets |
579,900 | 730,800 | ||||||
Oil and gas properties, net |
6,821,300 | 7,108,400 | ||||||
Long-term hedge receivable due from affiliate |
| 327,500 | ||||||
Long-term receivable-affiliate |
191,300 | | ||||||
$ | 7,592,500 | $ | 8,166,700 | |||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accrued liabilities |
$ | 15,500 | $ | 11,700 | ||||
Short-term hedge liability due to affiliate |
| 3,300 | ||||||
Total current liabilities |
15,500 | 15,000 | ||||||
Asset retirement obligations |
1,438,600 | 1,396,700 | ||||||
Long-term hedge liability due to affiliate |
| 58,000 | ||||||
Partners capital: |
||||||||
Managing general partner |
1,027,200 | 1,162,100 | ||||||
Limited partners (2,135 units) |
4,745,900 | 5,047,100 | ||||||
Accumulated other comprehensive income |
365,300 | 487,800 | ||||||
Total partners capital |
6,138,400 | 6,697,000 | ||||||
$ | 7,592,500 | $ | 8,166,700 | |||||
See accompanying notes to financial statements.
3
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ATLAS AMERICA PUBLIC #10 LTD.
STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
REVENUES |
||||||||||||||||
Natural gas and oil |
$ | 389,500 | $ | 460,500 | $ | 750,100 | $ | 897,300 | ||||||||
Interest income |
100 | 100 | 100 | 200 | ||||||||||||
Total revenues |
389,600 | 460,600 | 750,200 | 897,500 | ||||||||||||
COSTS AND EXPENSES |
||||||||||||||||
Production |
165,500 | 202,800 | 328,900 | 390,900 | ||||||||||||
Depletion |
154,900 | 173,700 | 287,100 | 362,100 | ||||||||||||
Accretion of asset retirement obligation |
21,000 | 17,100 | 41,900 | 34,200 | ||||||||||||
General and administrative |
29,000 | 37,200 | 66,600 | 72,100 | ||||||||||||
Total expenses |
370,400 | 430,800 | 724,500 | 859,300 | ||||||||||||
Net income |
$ | 19,200 | $ | 29,800 | $ | 25,700 | $ | 38,200 | ||||||||
Allocation of net income: |
||||||||||||||||
Managing general partner |
$ | 13,800 | $ | 42,400 | $ | 33,200 | $ | 80,700 | ||||||||
Limited partners |
$ | 5,400 | $ | (12,600 | ) | $ | (7,500 | ) | $ | (42,500 | ) | |||||
Net income (loss) per limited partnership unit |
$ | 2 | $ | (6 | ) | $ | (4 | ) | $ | (20 | ) | |||||
See accompanying notes to financial statements.
4
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ATLAS AMERICA PUBLIC #10 LTD.
STATEMENT OF CHANGES IN PARTNERS CAPITAL
FOR THE SIX MONTHS ENDED
June 30, 2011
(Unaudited)
(Unaudited)
Accumulated | ||||||||||||||||
Managing | Other | |||||||||||||||
General | Limited | Comprehensive | ||||||||||||||
Partner | Partners | Income (Loss) | Total | |||||||||||||
Balance at January 1, 2011 |
$ | 1,162,100 | $ | 5,047,100 | $ | 487,800 | $ | 6,697,000 | ||||||||
Participation in revenues and expenses: |
||||||||||||||||
Net production revenues |
106,700 | 314,500 | | 421,200 | ||||||||||||
Interest income |
| 100 | | 100 | ||||||||||||
Depletion |
(38,800 | ) | (248,300 | ) | | (287,100 | ) | |||||||||
Accretion of asset retirement obligation |
(13,400 | ) | (28,500 | ) | | (41,900 | ) | |||||||||
General and administrative |
(21,300 | ) | (45,300 | ) | | (66,600 | ) | |||||||||
Net income (loss) |
33,200 | (7,500 | ) | | 25,700 | |||||||||||
Other comprehensive income |
| | (122,500 | ) | (122,500 | ) | ||||||||||
Distributions to partners |
(168,100 | ) | (293,700 | ) | | (461,800 | ) | |||||||||
Balance at June 30, 2011 |
$ | 1,027,200 | $ | 4,745,900 | $ | 365,300 | $ | 6,138,400 | ||||||||
See accompanying notes to financial statements.
5
Table of Contents
ATLAS AMERICA PUBLIC #10 LTD
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 25,700 | $ | 38,200 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depletion |
287,100 | 362,100 | ||||||
Non-cash loss on hedge instruments |
33,300 | 51,400 | ||||||
Accretion of asset retirement obligations |
41,900 | 34,200 | ||||||
Decrease (increase) in accounts receivable affiliate |
46,700 | (86,000 | ) | |||||
Increase in accrued liabilities |
3,800 | 4,300 | ||||||
Net cash provided by operating activities |
438,500 | 404,200 | ||||||
Cash flows from financing activities: |
||||||||
Distributions to partners |
(432,000 | ) | (490,400 | ) | ||||
Net cash used in financing activities |
(432,000 | ) | (490,400 | ) | ||||
Net increase (decrease) in cash and cash equivalents |
6,500 | (86,200 | ) | |||||
Cash and cash equivalents at beginning of period |
53,300 | 86,300 | ||||||
Cash and cash equivalents at end of period |
$ | 59,800 | $ | 100 | ||||
Supplemental Schedule of non-cash financing activities: |
||||||||
Distribution to Managing General Partner |
$ | 29,800 | $ | | ||||
See accompanying notes to financial statements.
6
Table of Contents
ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS
June 30, 2011
(Unaudited)
NOTE 1 DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Atlas America Public #10 Ltd. (the Partnership) is a Pennsylvania limited partnership and
formed on July 5, 2001 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 sheet 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 June 30, 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 annual report on 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 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.
7
Table of Contents
ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 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 and six months ended June 30, 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 Partnerships MGP performs
ongoing credit evaluations of the Partnerships customers and adjusts credit limits based upon
payment history and the customers current creditworthiness, as determined by review of the
Partnerships customers credit information. Credit is extended on an unsecured basis to many of
its energy customers. At June 30, 2011 and December 31, 2010, the 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.
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Proved properties: |
||||||||
Leasehold interests |
$ | 338,500 | $ | 338,500 | ||||
Wells and related equipment |
25,662,700 | 25,662,700 | ||||||
26,001,200 | 26,001,200 | |||||||
Accumulated depletion |
(19,179,900 | ) | (18,892,800 | ) | ||||
Oil and gas properties, net |
$ | 6,821,300 | $ | 7,108,400 | ||||
8
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 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 and six months ended June 30, 2011.
During the year ended December 31, 2010, the Partnership recognized an impairment charge of
$936,600, net of an offsetting gain in accumulated other comprehensive income of $49,100.
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
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 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 June 30, 2011 and December 31, 2010 of $204,800 and $233,100, respectively, which are
included in accounts receivable affiliate within the Partnerships balance sheets.
Recently Adopted Accounting Standards
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update
2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to
present the total of comprehensive income, the components of net income, and the components of
other comprehensive income in either a single continuous statement of comprehensive income or in
two separate but consecutive statements. In both choices, an entity is required to present each
component of net income along with a total net income, each component of other comprehensive
income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to
present the components of other comprehensive income as part of the statement of changes in
partners capital. These changes apply to both annual and interim financial statements. Update
2011-05 will be effective for public entities fiscal years, and interim periods within those
years, beginning after December 15, 2011. The Partnership will apply the requirements of Update
2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material
impact on its financial position, results of operations or related disclosures.
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
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 3 ASSET RETIREMENT OBLIGATION (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, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Asset retirement obligation at beginning of
period |
$ | 1,417,600 | $ | 1,155,500 | $ | 1,396,700 | $ | 1,138,400 | ||||||||
Accretion expense |
21,000 | 17,100 | 41,900 | 34,200 | ||||||||||||
Asset retirement obligation at end of period |
$ | 1,438,600 | $ | 1,172,600 | $ | 1,438,600 | $ | 1,172,600 | ||||||||
NOTE 4 DERIVATIVE INSTRUMENTS
The MGP, on behalf of the Partnership, used a number of different derivative instruments,
principally swaps and collars, in connection with its commodity price risk management activities.
The MGP entered 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 received 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.
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.
11
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 4 DERIVATIVE INSTRUMENTS (Continued)
Prior to the acquisition on February 17, 2011 of the Transferred Business, Atlas Energy,
Inc. 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 June 30, 2011, the Partnership recorded a net receivable from the monetized
derivative instruments of $224,400 in accounts receivable-affiliate and $191,300 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 generated over the period of the original instruments contracts. As a result of
the monetization and the early settlement of natural gas and oil derivative instruments 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 $365,300 as of June 30, 2011. Unrealized gains, net of the MGPs interest,
previously recognized into income as a result of prior period impairments included in accumulated
other comprehensive income were $19,300 and $31,100 for the year ended December 31, 2010 and prior
periods, respectively. The MGPs portion of the unrealized gains was written-off as part of the
terms related to the acquisition of the Transferred Business. For the six months ended June 30,
2011, the Partnership reclassified $29,800 of unrealized gains previously recognized into income
from prior period impairments related to the MGP from a hedge receivable due from affiliate to a
non-cash distribution to the MGP. As such, $29,800 was recorded as a distribution to partners on
the statement of changes in partners capital. During the six months ended June 30, 2011, $87,700
of monetized proceeds were recorded by the Partnership and allocated only to the limited partners.
Of the remaining $365,300 of net unrealized gain in accumulated other comprehensive income, the
Partnership will reclassify $197,100 of net gains to the Partnerships statements of operations
over the next twelve month period and the remaining $168,200 in later periods.
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 June 30, 2011 and 2010:
Fair Value of Derivative Instruments:
Fair Value | ||||||
Balance Sheet | December 31, | |||||
Derivatives in Cash Flow Hedging Relationships | Location | 2010 | ||||
Commodity Contracts | Current assets |
$ | 335,100 | |||
Long-term assets |
327,500 | |||||
662,600 | ||||||
Current liabilities |
(3,300 | ) | ||||
Long-term liabilities |
(58,000 | ) | ||||
(61,300 | ) | |||||
Total |
$ | 601,300 | ||||
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 4 DERIVATIVE INSTRUMENTS (Continued)
Effects of Derivative Instruments on statements of operations:
Three Months Ended | Six Months Ended | |||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||
Derivative in Cash Flow Hedging Relationships |
Gain (Loss) Recognized in OCI on Derivatives | |||||||||||||||||
Commodity Contracts | $ | | $ | (41,200 | ) | $ | 26,700 | $ | 442,300 | |||||||||
Three Months Ended | Six Months Ended | |||||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||
Location of Gain Reclassified from Accumulated OCI into Income |
Gain Reclassified from OCI into Net Income | |||||||||||||||||
Gas and Oil Revenue |
$ | 75,300 | $ | 89,300 | $ | 201,200 | $ | 177,100 | ||||||||||
NOTE 5 COMPREHENSIVE (LOSS) INCOME
Comprehensive (loss) income includes net income 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 income. These changes, other than net income, are
referred to as other comprehensive (loss) income and for the Partnership includes changes in the
fair value of unsettled derivative contracts accounted for as cash flow hedges, and changes in the
estimated amount of future monetized proceeds to be received (See Note 4). The monetized proceeds
included in accounts receivable affiliate have been allocated to the Partnership based on estimated
future production in relation to all other Partnerships future production eligible to receive
monetized hedge proceeds. As actual production is realized, there may be a corresponding difference
in the Partnerships actual share of monetized hedge proceeds received, than what was previously
estimated. This component is shown as Difference in estimated monetized gains receivable. The
following table sets forth the calculation of the Partnerships comprehensive (loss) income:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 19,200 | $ | 29,800 | $ | 25,700 | $ | 38,200 | ||||||||
Other comprehensive (loss) income: |
||||||||||||||||
Unrealized holding gain (loss) on
hedging contracts |
| (41,200 | ) | 26,700 | 442,300 | |||||||||||
MGP portion
of non-cash loss on hedging instruments |
| | 29,800 | | ||||||||||||
Difference in estimated monetized
gains receivable |
96,000 | | 22,200 | | ||||||||||||
Less: reclassification adjustment
for gains realized in net income |
(75,300 | ) | (89,300 | ) | (201,200 | ) | (177,100 | ) | ||||||||
Total other comprehensive (loss) income |
(65,700 | ) | (130,500 | ) | (122,500 | ) | 265,200 | |||||||||
Comprehensive (loss) income |
$ | (46,500 | ) | $ | (100,700 | ) | $ | (96,800 | ) | $ | 303,400 | |||||
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
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 4). 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.
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 the MGP and its
affiliates as provided under its Partnership Agreement:
| Administrative costs which are included in general and administrative expenses in the
Partnerships statement of operations are payable at $75 per well per month.
Administrative costs incurred for the three and six months ended June 30, 2011 were
$20,900 and $41,200, respectively. Administrative costs incurred for the three and six
months ended June 30, 2010 were $21,500 and $42,700 respectively. |
| Monthly well supervision fees which are included in production expenses in the
Partnerships statement of operations are payable at $329 per well per month in 2011 and
2010, respectively, for operating and maintaining the wells. Well supervision fees
incurred for the three and six months ended June 30, 2011 were $91,800 and $180,700,
respectively. Well supervision fees incurred for the three and six months ended June 30,
2010 were $94,500 and $187,300, respectively. |
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ATLAS AMERICA PUBLIC #10 LTD.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 7 TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES (Continued)
| Transportation fees which are included in production expenses in the Partnerships
statement 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, 2011 were
$45,700 and $91,500, respectively. Transportation fees incurred for the three and six
months ended June 30, 2010 were $51,300 and $106,400, 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.
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.
Overview
The following discussion provides information to assist in understanding our financial
condition and result of operations. Our operating cash flows are generated from our wells, which
produce primarily natural gas, but also some oil. Our produced natural gas and oil is then
delivered to market through affiliated or third-party gas gathering systems. Our ongoing operating
and maintenance costs have been and are expected to be fulfilled through revenues from the sale of
our natural gas and oil production. We pay our managing general partner, as operator, a monthly
well supervision fee, which covers all normal and regularly recurring operating expenses for the
production and sale of natural gas and oil such as:
| well tending, routine maintenance and adjustment; |
| reading meters, recording production, pumping, maintaining appropriate books and
records; and |
| preparation of reports for us and government agencies. |
The well supervision fees, however, do not include costs and expenses related to the purchase
of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for
third-party services, materials, and a competitive charge for services performed directly by our
managing general partner or its affiliates. Also, beginning one year after each of our wells has
been placed into production our managing general partner, as operator, may retain $200 per month,
per well to cover the estimated future plugging and abandonment costs of the well. As of June 30,
2011, our managing general partner had not withheld any funds for this purpose. Our managing
general partner intends to produce our wells until they are depleted or become uneconomical to
produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled
and no additional funds will be required for drilling.
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Table of Contents
Markets and Competition
The availability of a ready market for natural gas and oil produced by us, and the price
obtained, depends on numerous factors beyond our control, including the extent of domestic
production, imports of foreign natural gas and oil, political instability or terrorist acts in oil
and gas producing countries and regions, market demand, competition from other energy sources, the
effect of federal regulation on the sale of natural gas and oil in interstate commerce, other
governmental regulation of the production and transportation of natural gas and oil and the
proximity, availability and capacity of pipelines and other required facilities. Our managing
general partner is responsible for selling our natural gas production. During 2011 and 2010, we
experienced no problems in selling our natural gas and oil. Product availability and price are the
principal means of competition in selling natural gas and oil production. While it is impossible to
accurately determine our comparative position in the industry, we do not consider our operations to
be a significant factor in the industry.
We have drilled and currently operate wells located in Pennsylvania and Ohio. 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.
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, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Production revenues (in thousands): |
||||||||||||||||
Gas |
$ | 365 | $ | 417 | $ | 719 | $ | 849 | ||||||||
Oil |
24 | 44 | 31 | 48 | ||||||||||||
Total |
$ | 389 | $ | 461 | $ | 750 | $ | 897 | ||||||||
Production volumes: |
||||||||||||||||
Gas (mcf/day) (1) |
729 | 668 | 679 | 717 | ||||||||||||
Oil (bbls/day) (1) |
3 | 6 | 2 | 3 | ||||||||||||
Total (mcfe/day) (1) |
747 | 704 | 691 | 735 | ||||||||||||
Average sales prices: (2) |
||||||||||||||||
Gas (per mcf) (1) (3) |
$ | 5.70 | $ | 7.28 | $ | 6.12 | $ | 6.94 | ||||||||
Oil (per bbl) (1) (4) |
$ | 100.66 | $ | 79.45 | $ | 95.58 | $ | 78.13 | ||||||||
Average production costs: |
||||||||||||||||
As a percent of revenues |
42 | % | 44 | % | 44 | % | 44 | % | ||||||||
Per mcfe (1) |
$ | 2.44 | $ | 3.16 | $ | 2.63 | $ | 2.93 | ||||||||
Depletion per mcfe |
$ | 2.29 | $ | 2.71 | $ | 2.30 | $ | 2.71 |
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(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 $13,000 and $33,300 for the three months
and six months ended June 30, 2011, respectively previously recognized derivative gains
were $25,600 and $50,700 for the three and six months ended June 30, 2010,
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.
There were no previously recognized gains for the three and six months ended June 30,
2011. Previously recognized derivative gains were $400 and $700 for the three and six
months ended June 30, 2010, respectively. The derivative gains are included in other
comprehensive income and resulted from prior period impairment charges. |
Natural Gas Revenues. Our natural gas revenues were $365,000 and $417,000 for the three
months ended June 30, 2011 and 2010, respectively, a decrease of $52,000 (12%). The $52,000
decrease in natural gas revenues for the three months ended June 30, 2010 as compared to the prior
year similar period was attributable to an $89,500 decrease in our natural gas sales prices after
the effect of financial hedges, which were driven by market conditions and a $37,500 increase in
production volumes. Our production volumes increased to 729 mcf per day for the three months ended
June 30, 2011 from 668 mcf per day for the three months ended June 30, 2010, an increase of 61 mcf
per day (9%). Our production volumes increased for the three months ended June 30, 2011 due to
certain wells being moved to a new gathering system.
Our natural gas revenues were $718,700 and $848,900 for the six months ended June 30, 2011 and
2010, respectively, a decrease of $130,200 (15%). The $130,200 decrease in natural gas revenues for
the six months ended June 30, 2011 as compared to the prior year similar period was attributable to
a $86,100 decrease in our natural gas sales prices after the effect of financial hedges, which were
driven by market conditions, and a $44,100 decrease in production volumes. Our production volumes
decreased to 679 mcf per day for the six months ended June 30, 2011 from 717 mcf per day for the
six months ended June 30, 2010, a decrease of 38 mcf per day (5%). The overall decrease in natural
gas production volumes for the six months ended June 30, 2011 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 $24,500 and $43,500 for the three months ended
June 30, 2011 and 2010, respectively, a decrease of $19,000 (44%). The $19,000 decrease in oil
revenues for the three months ended June 30, 2011 as compared to the prior year similar period was
attributable to a $24,300 decrease in production volumes, partially offset by a $5,300 increase in
oil prices after the effect of financial hedges. Our production volumes decreased to 3 bbls per day
for the three months ended June 30, 2011 from 6 bbls per day for the three months ended June 30,
2010, a decrease of 3 bbls per day (50%).
Our oil revenues were $31,400 and $48,400 for the six months ended June 30, 2011 and 2010,
respectively, a decrease of $17,000 (35%). The $17,000 decrease in oil revenues for the six months
ended June 30, 2011 as compared to the prior year similar period was attributable to a $23,100
decrease in production volumes, partially offset by a $6,100 increase in oil prices after the
effect of financial hedges. Our production volumes decreased to 2 bbls per day for the six months
ended June 30, 2011 from 3 bbls per day for the six months ended June 30, 2010, a decrease of 1 bbl
per day (33%).
Costs and Expenses. Production expenses were $165,500 and $202,800 for the three months ended
June 30, 2011 and 2010, respectively, a decrease of $37,300 (18%). Production expenses were
$328,900 and $390,900 for the six months ended June 30, 2011 and 2010, respectively, a decrease of
$62,000 (16%). These decreases were primarily attributable to lower transportation fees and other
variable expenses as compared to the prior year similar period.
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Table of Contents
Depletion of oil and gas properties as a percentage of oil and gas revenues were 40% and 38%
for the three months ended June 30, 2011 and 2010, respectively; and 38% and 40% for the six months
ended June 30, 2011 and 2010, 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, 2011 and 2010 were
$29,000 and $37,200, respectively, a decrease of $8,200 (22%). For the six months ended June 30,
2011 and 2010, these expenses were $66,600 and $72,100 a decrease, respectively, a decrease of
$5,500 (8%). These expenses include third-party costs for services as well as the monthly
administrative fees charged by our MGP. These decreases were primarily attributable to lower
third-party costs as compared to the prior year similar period.
Liquidity and Capital Resources
Cash provided by operating activities increased $34,300 in the six months ended June 30, 2011
to $438,500 as compared to $404,200 for the six months ended June 30, 2010. This increase was due
to the change in accounts receivable-affiliate increasing operating cash flows by $132,700 for the
six months ended June 30, 2011, as compared to the six months ended June 30, 2010. The increase was
partially offset by a decrease in net income before depletion and accretion of $79,800 and a
non-cash loss on hedge instruments of $18,100.
Cash used in financing activities decreased $58,400 during the six months ended June 30, 2011
to $432,000 from $490,400 for the six months ended June 30, 2010. This decrease was due to a
decrease in cash distributions to partners.
Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2011,
our MGP had not withheld any funds for this purpose. 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.
The Partnership is generally limited to the amount of funds generated by the cash flows from
our operations, which we believe is adequate to fund future operations and distributions to our
partners. Historically, there has been no need to borrow funds from our MGP to fund 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 (April 2002) and expiring 60 months from that date. The Partnership completed
the subordination period effective March 2007. Since inception of the Partnership, the MGP has not
been required to subordinate any of its revenues to its limited partners.
Critical Accounting Policies and Estimates
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.
18
Table of Contents
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 MGPs 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 MGPs 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 MGPs Chairman of the Board of Directors, Chief Executive
Officer, President and Chief Financial Officer, concluded that, at June 30, 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.
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 MGPs 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.
ITEM 6. | EXHIBITS |
EXHIBIT INDEX
Exhibit No. | Description | |||
4.0 | Amended and Restated
Certificate and Agreement of Limited Partnership for Atlas America Public #10
Ltd. (1) |
|||
31.1 | Certification Pursuant to Rule 13a-14/15(d)-14 |
|||
31.2 | Certification Pursuant to Rule 13a-14/15(d)-14 |
|||
32.1 | Section 1350 Certification |
|||
32.2 | Section 1350 Certification |
|||
101 | Interactive data file |
(1) | Filed on August 14, 2001 in the Form S-1 Registration Statement dated August 14, 2001, File No. 333-67522 |
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SIGNATURES
Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Atlas America Public #10 Ltd.
ATLAS RESOURCES, LLC, Managing General Partner |
||||
Date: August 15, 2011 | By: | /s/ FREDDIE M. KOTEK | ||
Freddie M. Kotek, Chairman of the Board of Directors, |
||||
Chief Executive Officer and President | ||||
In accordance with the Exchange Act, this report has been signed by the following person on
behalf of the registrant and in the capacities and on the dates indicated.
Date: August 15, 2011 | By: | /s/ SEAN P. MCGRATH | ||
Sean P. McGrath, Chief Financial Officer |
||||
20