Item 2 “Properties” for information concerning our wells.
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 MGP a monthly well supervision fee of $337 per well, as outlined in our drilling and operating agreement. This well supervision fee 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 to 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 will pay cost for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates. Also, beginning three years after each of our wells has been placed into production our MGP, as operator, may retain $200 per month per well to cover our estimated future plugging and abandonment costs. As of December 31, 2009 our MGP had not withheld any funds for this purpose.
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, import 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 MGP is responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2, “Properties.” During 2009 and 2008, 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. See Item 2, “Properties” regarding the marketing of our natural gas and oil.
Governmental Regulation. The energy industry in general is heavily regulated by federal and state authorities, including regulation of production, environmental quality, and pollution control. The intent of federal and state regulations generally is to prevent waste, protect rights to produce natural gas and oil between owners in a common reservoir and control contamination of the environment. Failure to comply with regulatory requirements can result in substantial fines and other penalties. The following discussion of the regulation of the United States of America energy industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.
Regulation of oil and gas producing activities. State regulatory agencies where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas operations such as ours including supervising the production activities and the transportation of natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, and our oil and gas operations in Ohio are regulated by the Ohio Department of Natural Resources, Division of Oil and Gas.
Among other things, these regulations involve:
•
new well permit and well registration requirements, procedures and fees;
•
minimum well spacing requirements;
•
restrictions on well locations and underground gas storage;
•
certain well site restoration, groundwater protection and safety measures;
•
landowner notification requirements;
•
certain bonding or other security measures;
•
various reporting requirements;
•
well plugging standards and procedures; and
•
broad enforcement powers.
Environmental and Safety Regulation. Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas or oil can be liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the owners’ or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.
We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Our producing activities also must comply with various federal, state and local laws not mentioned, including those covering the discharge of materials into the environment, or otherwise relating to the protection of the environment.
Where can you find more information. We file a Form 10-K Annual Reports and Form 10-Q Quarterly Reports, as well as other non-recurring special purpose reports, with the Securities and Exchange Commission. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800- SEC-0330 for further information.
Additionally, our MGP will provide copies of any of these reports to you without charge. Such requests should be made to:
Atlas America Public #9 Ltd.
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108
ITEM 2.
DESCRIPTION OF PROPERTIES
Drilling Activity. For the years ended December 31, 2009 and 2008, we did not drill any wells nor do we expect to do so in future years.
Summary of Producing Wells. The table below presents the number of our producing gross and net wells at December 31, 2009 in which we have a working interest. All wells are located in the Appalachian Basin.
Production. The following table presents the quantities of natural gas and oil we produced (net to our interest), our average sales price, and our average production (lifting) cost per equivalent unit of production for the periods indicated.
(1)
“Mcf” represents one thousand cubic feet of natural gas. “Mcfe” represents a thousand cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).
(2)
Lifting costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, production taxes, insurance and gathering charges.
Natural Gas and Oil Reserve Information. In December 2008, the Securities and Exchange Commission “SEC” approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:
•
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
•
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
•
Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.
•
Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”
•
Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
•
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers’ criteria.
We have complied with these disclosure requirements for the year ended December 31, 2009.
The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties. For the year ended December 31, 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009 and then applied any basis and British Thermal Units (“btu”) differentials specifically applicable to each oil and gas property based on location and pricing details. For the year ended December 31, 2008, we based our estimates of proved reserves using the natural gas and oil prices as of December 31, 2008 of the respective year. The following table summarizes the natural gas and oil prices used in the estimation of proved reserves:
Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The preparation of our natural gas and oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, we retained Wright & Company, a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K. Results of production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.
We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deducted when applicable, operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. The following table presents our reserve information for the previous two years. We base the estimates on operating methods and conditions prevailing as of the dates indicated:
(1)
“Proved reserves” generally refers to the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements, but not escalations based on future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.
(2)
“Proved developed oil and gas reserves” generally refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
(3)
“The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.
(4)
Please see Regulation S-X rule 4-10 for complete definitions of each reserve category.
(5)
This value per $10,000 unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of a unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the partnership agreement.
We have not filed any estimates of our gas and oil reserves with, nor were such estimates included in any reports to, any Federal or foreign governmental agency other than the SEC within the 12 months before the date of this filing.
Title to Properties. We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, our MGP conducts only a perfunctory title examination at the time it acquires a property. Before our MGP commences drilling operations, it conducts an extensive title examination and performs curative work on defects that it deems significant. Our MGP has obtained title examinations for substantially all of our producing properties. No single property represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the natural gas industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.
Acreage. The table below presents, by state, the estimated acres of developed oil and gas acreage in which we had an interest at December 31, 2009. There was no undeveloped acreage at December 31, 2009.
(1)
A “gross” acre is an acre in which we own a working interest.
(2)
A “net” acre represents the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre.
Delivery Commitments. Atlas Energy and its affiliates, have a natural gas supply agreement with Hess Corporation for a 10-year term which began on April 1, 1999. The agreement was formerly with First Energy Solutions Corporation and was acquired by Hess Corporation in 2005. For the next 12 months, we anticipate that approximately 11% of our gas will be sold through this agreement with Hess Corporation. Atlas Energy markets the remainder of our natural gas, which is principally located in the Fayette County, PA area, primarily to Constellation New Energy, Colonial Energy, Inc., South Jersey Resources Group, LLC and to other third-party natural gas purchasers or marketers.
The pricing arrangements with Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group, LLC, and other third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commissions or NYMEX spot market price. The total price received for our gas is a combination of the monthly NYMEX spot price plus a basis adjustment. For example, the NYMEX spot price is the base price and there is an additional premium paid, because of the location of the gas (the Appalachian Basin) in relation to the gas market, which is referred to as the “basis.”
Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements with Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group, LLC and the other third-party gas purchasers or marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions through those companies. Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group, LLC and the other third-party purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements available to us and its other partnerships. The price paid by Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group, LLC and any other third-party purchasers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market price. Also, Atlas Energy’s hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. The overall portion of our natural gas portfolio that is hedged changes from time to time.
To assure that all financial instruments will be used solely for hedging price risks, and not for speculative purposes, Atlas Energy has established a committee to assure that all financial trading is done in compliance with Atlas Energy’s hedging policies and procedures. Atlas Energy does not intend to contract for positions that it cannot offset with actual production.
We are not required to provide any fixed and determinable quantities of gas under any agreement other than with Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group LLC and the other third-party gas purchasers or marketers.
The MGP is not aware of any legal proceedings filed against us.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.
None.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
Market Information. There is no established public trading market for our units and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our partnership agreement which requires:
•
our managing general partner consent;
•
the transfer not result in materially adverse tax consequences to us; and
•
the transfer not violate federal or state securities laws.
An assignee of a unit may become a substituted partner only upon meeting the following conditions:
•
the assignor gives the assignee the right;
•
our managing general partner consents to the substitution;
•
the assignee pays to us all costs and expenses incurred in connection with the substitution; and
•
the assignee executes and delivers the instruments which our managing general partner requires to effect the substitution and to confirm his or her agreement to be bound by the terms of our partnership agreement.
A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote.
Holders. As of December 31, 2009, we had 536 unit holders.
Distributions. Our MGP reviews our accounts quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds, which our MGP determines are not necessary for us to retain, to our partners. We will not advance or borrow funds for purposes of making distributions.
The determination of our revenues and costs is made in accordance with generally accepted accounting principles, consistently applied, and cash distributions to our MGP may only be made in conjunction with distributions to our limited partners.
During the years ended December 31, 2009 and 2008, we distributed the following:
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS
The following discussion provides information to assist in understanding our financial condition and result of operations. This discussion should be read in conjunction with our financial statements and related notes appearing elsewhere in this report.
General. We were formed as a Pennsylvania limited partnership on July 27, 2000, with Atlas Resources, LLC. as our Managing General Partner, or MGP, to drill natural gas developmental wells. Our MGP, Atlas Resources, LLC, is an indirect subsidiary of Atlas Energy, Inc., (NASDAQ: ATLS) or Atlas Energy. We have no current plans to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling.
Atlas Energy’s focus is on the development and production of natural gas and oil in the Appalachian Basin, Michigan Basin and the Illinois Basin, regions of the United States of America. Atlas Energy is also 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 Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc. provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise capital.
Results of Operations. The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:
Natural Gas Revenues. Our natural gas revenues were $1,450,700 and $2,196,000 for the years ended December 31, 2009 and 2008, respectively, a decrease of $745,300 (34%). The $745,300 decrease in natural gas revenues for the year ended December 31, 2009 as compared to the prior year period was attributable to a $472,500 decrease in natural gas production volumes and a $272,800 decrease due to lower natural gas sales prices after the effect of financial hedges, which were driven by market conditions. Our production volumes decreased to 492 mcf per day for the year ended December 31, 2009 from 625 mcf per day for the year ended December 31, 2008, a decrease of 133 mcf per day (21%). The overall decrease in natural gas production volumes resulted primarily from the normal decline inherent in the life of a well.
The price we receive for our natural gas is primarily a result of the index driven agreement with Constellation New Energy, Colonial Energy, Inc., Hess Corporation, South Jersey Resources Group, LLC and our other natural gas purchasers. See Item 2 “Properties.” Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions.
Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $125,000 and $162,100 for the years ended December 31, 2009 and 2008, respectively, a decrease of $37,100 (23%). The $37,100 decrease in oil revenue for the years ended December 31, 2009 as compared to the prior year period was attributable to a $71,200 decrease due to lower oil prices, partially offset by a $34,100 increase in production volumes. Our production volumes increased to 5.46 bbls per day for the year ended December 31, 2009 from 4.5 bbls per day for the years ended December 31, 2008, an increase of .96 bbl per day (21%).
Expenses. Production expenses were $649,200 and $662,100 for the years ended December 31, 2009 and 2008, respectively, a decrease of $12,900 (2%). This decrease was primarily attributable to lower transportation expenses, which were affected by a decrease in production volumes.
Depletion of our oil and gas properties as a percentage of oil and gas revenues was 35% and 22% for the years ended December 31, 2009 and 2008, respectively. This percentage change is directly attributable to revenues, oil and gas reserve quantities, product prices and production volumes.
General and Administrative expenses were $115,800 and $118,800 for the years ended December 31, 2009 and 2008, respectively, a decrease of $3,000 (3%). These expenses include third-party costs for services as well as the monthly administrative fee charged by our MGP and vary from period to period due to the timing and billing of the costs and services provided to us. This decrease was primarily attributable to lower third party costs as compared to the prior year similar period.
Liquidity and Capital Resources. Cash provided by operating activities decreased $642,200 to $938,500 for the year ended December 31, 2009 from $1,580,700 for the year ended December 31, 2008. This decrease was primarily due to a decrease in net earnings before depletion and accretion of $769,300 partially offset by the change in accounts-receivable affiliate increasing operating cash flows by $132,100.
Cash used in financing activities decreased $560,500 to $1,070,400 for the year ended December 31, 2009 from $1,630,900 for the year ended December 31, 2008. This decrease was due a decrease in cash distributions to partners.
Our MGP may withhold funds for future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.
We believe that our future cash flows from operations and amounts available from borrowings from our MGP or its affiliates, if any, will be adequate to fund our operations.
Critical Accounting Policies and Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include depletion and depreciation, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements included in Item 8, “Financial Statements.” The critical accounting policies and estimates we have identified are discussed below.
Impairment of Long-Lived Assets. The cost of oil and gas properties, less estimated salvage value, is depleted on the units-of-production method and is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. There was no impairment charges for the years ended December 31, 2009 or 2008.
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1 - Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 - Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
The MGP uses a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. The commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.
Assets and liabilities that are required to be measured at fair value on a nonrecurring basis include our oil and gas properties and asset retirement obligations (“ARO’s”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted risk-free rate and inflation rates.
Reserve Estimates. Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect partnership distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.
Asset Retirement Obligations. On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our operating assets. We also estimate the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and a credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.
Working Interest. Our agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions, (“working interest”). Our 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas America Public #9 Ltd.
We have audited the accompanying balance sheets of Atlas America Public #9 Ltd. (a Pennsylvania Limited Partnership) as of December 31, 2009 and 2008, and the related statements of operations, comprehensive income, changes in partners’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Public #9 Ltd. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 30, 2010
ATLAS AMERICA PUBLIC #9 LTD.
BALANCE SHEETS
DECEMBER 31,
The accompanying notes are an integral part of these financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2009 and 2008
The accompanying notes are an integral part of these financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED DECEMBER 31, 2009 and 2008
The accompanying notes are an integral part of these financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2009 and 2008
The accompanying notes are an integral part of these financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2009 and 2008
The accompanying notes are an integral part of these financial statements.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008
NOTE 1 - DESCRIPTION OF BUSINESS
Atlas America Public #9 Ltd. (the “Partnership”) is a Pennsylvania Limited Partnership which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and Operator, and 535 Limited Partners. The Partnership was formed on July 27, 2000 to drill and operate gas wells located primarily in western Pennsylvania and Ohio. At December 31, 2009, the Partnership had various working interests in 82 gross wells.
In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc, (NASDAQ:ATLS). Atlas Resources, LLC serves as the Partnership’s MGP.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of significant accounting policies consistently applied in the preparation of the accompanying financial statements follows:
Use of Estimates
The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.
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 customer’s current creditworthiness, as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At December 31, 2009 and 2008, the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue Recognition
The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest and/or overriding royalty. Generally, the MGP’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.
Because there are timing differences between the delivery of the Partnership’s natural gas and oil and its receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based upon volumetric data from its records and its estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Partnership had unbilled trade receivables of $243,000 at December 31, 2009 and $343,700 at December 31, 2008, which are included in Accounts receivable - affiliate on the Partnership’s Balance Sheets.
Fair Value of Financial Instruments
The carrying amounts of the Partnership cash and receivables approximate fair values because of the short maturities of these instruments.
For derivatives the carrying value approximates fair value because they have been marked to market.
Supplemental Cash Flow Information
The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income taxes for the years ended December 31, 2009 and 2008.
Concentration of Credit Risk
Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2009, the Partnership had $84,200 in deposits at one bank of which none was over the insurance limit of the Federal Deposit Insurance Corporation and at December 31, 2008 the Partnership had $222,000 in deposits at one bank of which none was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
Comprehensive Income
Comprehensive income includes net income and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net income, 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.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Working Interest
The Partnership agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions, (“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 net 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.
Oil and Gas Properties
The Partnership follows the successful-efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is determined on a field-by-field basis using the units-of-production method for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of the property are capitalized. The Partnership is required to consider estimated salvage value in the calculation of depletion.
Oil and gas properties consist of the following at the dates indicated:
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows. The review is done by determining if the historical cost of proved properties less the applicable accumulated depletion and salvage value is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. 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. The fair market value is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009 and 2008. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. There was no impairment charge for the years ended December 31, 2009 and 2008.
Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the Statements of Operations.
Asset Retirement Obligation
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities, or asset retirement obligations (see Note 8). The Partnership recognizes a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of the liability can be made. The associated asset retirement costs are capitalized as part, of the carrying amount of the long-lived asset.
Environmental Matters
The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Atlas Energy maintains insurance that may cover in whole or in part certain environmental expenditures. For the years ended December 31, 2009 and 2008, the Partnership had no environmental matters requiring specific disclosure or requiring recording of a liability.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Major Customers
The Partnership’s natural gas is sold under contract to various purchasers. For the year ended December 31, 2009, sales to Constellation New Energy, Colonial Energy, Inc., Hess Corporation and South Jersey Resources Group, LLC, accounted for 16%, 11% and 11% and 10%, respectively, of total revenues. For the year ended December 31, 2008, sales to South Jersey Resources Group, LLC, Interstate Gas Supply, Inc., and Hess Corporation, accounted for 20%, 13% and 11%, respectively, of total revenues. No other customers accounted for 10% or more of total revenues for the years ended December 31, 2009 and 2008.
Income Taxes
The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.
Recently Adopted Accounting Standards
In February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-09 “Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 amends Accounting Standards Codification (“ASC”) 855-10-50-1 to clarify that all entities other than SEC filers must disclose (1) the date through, which subsequent events have been evaluated and (2) whether that date is the date the financial statements were issued or available to be issued. However, the date-disclosure exemption for SEC filers does not relieve management from its responsibility to evaluate subsequent events through the date on which financial statements are issued. The Partnership adopted the requirements of Update 2010-09 on December 31, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Extractive Activities Oil and Gas (Topic 932) - Oil and Gas Reserve Estimation and Disclosures” (“Update 2010-03”). Update 2010-03 includes amendments to ASC Topic 932 “Extractive Activities - Oil and Gas,” to include within the ASC the reporting requirements covered in the Securities and Exchange Commission’s (“SEC”) final rule, “Modernization of Oil and Gas Reporting” issued on December 31, 2008. The Partnership adopted the requirements of Update 2010-03 on December 31, 2009. These new disclosure requirements include provisions that:
•
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations;
•
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date;
•
Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves;
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards (Continued)
•
Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”;
•
Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and
•
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required with regard to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.
The Partnership has complied with the disclosure requirements for the year ended December 31, 2009.
In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures - Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Partnership adopted the requirements of Update 2009-05 on September 30, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.
In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 - Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB ASC as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Partnership. The Partnership adopted the requirements of Update 2009-01 for its financial statements on September 30, 2009, and it did not have a material impact on its financial statement disclosures.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards (Continued)
In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009, and it did not have a material impact on its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.
In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted these requirements on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.
In March 2008, the FASB issued ASC 815-10-50-1, “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815-10-50-1”), to require enhanced disclosure about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership adopted the requirements of this section of ASC 815-10-50-1 on January 1, 2009, and it did not have a material impact on its financial position or results of operations (see Note 6).
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 3 - PARTICIPATION IN REVENUES AND COSTS
The MGP and the Limited Partners generally participate in revenues and costs in the following manner:
(1)
Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 7% of the partnership revenues.
(2)
These costs will be charged to the partners in the same ratio as the related production revenues are credited.
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under the Partnership agreement:
The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable - affiliate on the Partnership’s Balance Sheets represents the net production revenues due from the MGP.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 5 - COMMITMENTS
Subject to certain conditions, investor partners may present their interests for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation. As of December 31, 2009 the MGP had purchased less than 1% of investor partner units.
Beginning three years after each of the Partnership’s wells has been placed into production the MGP, as operator, may retain $200 per month per well to cover our estimated future plugging and abandonment costs. As of December 31, 2009 the MGP has not withheld any such funds.
NOTE 6 - DERIVATIVE INSTRUMENTS
The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge the Partnership’s forecasted natural gas, crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil and condensate 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.
The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s Statements of Operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners capital as accumulated other comprehensive income and will reclassify commodity derivatives to gas and oil production revenues for in the Partnership’s Statements of Operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its Statements of Operations as they occur. The following table summarizes the fair value of derivative instruments as of December 31, 2009 and 2008.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
Fair Value of Derivative Instruments:
Effects of Derivative Instruments on Statements of Operations:
At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, options contracts, and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. 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.
At December 31, 2009, the Partnership reflected a net hedge asset on its Balance Sheets of $407,900. Of the $407,900 net gain in accumulated other comprehensive income at December 31, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $240,100 of net gains to its Statements of Operations over the next twelve month period as these contracts expire, and $167,800 of net gains in later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized no gains or losses during the years ended December 31, 2009 and 2008, respectively, for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
As of December 31, 2009, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:
Natural Gas Fixed Price Swaps
Natural Gas Costless Collars
Crude Oil Fixed Price Swaps
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
Crude Oil Costless Collars
(1)
MMBTU represents million British Thermal Units.
(2)
Fair value based on forward NYMEX natural gas prices.
(3)
Fair value based on forward WTI crude oil prices.
NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value.
Level 1 -
Unadjusted quoted prices in active markets for identical 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.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership’s derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Assets and Liabilities measured at fair value at December 31, 2009 and 2008 were as follows.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The Partnership estimates the fair value of asset retirement obligations, using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amount and timing of settlements; the risk-free rate of the Partnership; and estimated inflation rates (see Note 8).
The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The fair market value using Level 3 inputs is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009 and 2008 (see Note 2).
NOTE 8 - ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells. The associated asset retirement costs are capitalized as part of oil and gas properties. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed risk free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 8 - ASSET RETIREMENT OBLIGATION (Continued)
NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
(1) Capitalized Costs Related to Oil and Gas Producing Activities
The following table presents the capitalized costs related to natural gas and oil producing activities at the periods indicated:
(2) Oil and Gas Reserve Information
In accordance with the modernization of oil and gas accounting (see Note 2), the Partnership changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows are estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules.
The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, the Company retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.
The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed, net to the Partnership’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the previous two years. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.
ATLAS AMERICA PUBLIC #9 LTD.
NOTES TO FINANCIAL STATEMENTS - (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 9 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Partnership’s oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, as of December 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.
Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2009 was effective.
This annual report does not include an attestation report by the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108, which is also our MGP’s primary office.
Executive Officers and Directors. The executive officers and directors of our MGP will serve until their successors are elected. The executive officers and directors of the MGP are as follows:
With respect to the biographical information set forth below:
•
the approximate amount of an individual’s professional time devoted to the business and affairs of our MGP and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and
•
for those individuals who also hold senior positions with other affiliates of our MGP, if it is stated that they devote approximately 100% of their professional time to our MGP and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between our MGP and Atlas America as compared with the other affiliates of our MGP, such as Viking Resources or Resource Energy.
Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004. Kotek will devote approximately 95% of his professional time to the business and affairs of the MGP and Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.
Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served as Vice President of Land and Geology for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the MGP. Mr. Carolas is a certified petroleum geologist and has been with the MGP and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC, and Atlas Energy Management, Inc.
Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas America, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Jack L. Hollander. Senior Vice President - Direct Participation Programs since January 2002 and before that he served as Vice President - Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President - Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Sean P. McGrath has been our Chief Accounting Officer and the Chief Accounting Officer of Atlas Energy Resources since December 2008. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline Holdings GP from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant. Mr. McGrath will devote approximately 70% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.
Matthew A. Jones has been our Chief Financial Officer since March 2005 and an Executive Vice President since October 2009. Mr. Jones has been the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief Financial Officer of Atlas Pipeline Holdings GP from January 2006 until September 2009 as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones has served as a director of Atlas Pipeline Holdings GP since February 2006. Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.
Audit Committee Financial Expert. The Board of Directors of our MGP acts as the audit committee. The Board of Directors has determined that Freddie M. Kotek, Chairman and President of the MGP, meets the requirement of an “audit committee financial expert.” He is not independent.
Remuneration of Officers and Directors. No officer or director of the MGP will receive any direct remuneration or other compensation from the Partnership. These persons will receive compensation solely from affiliated companies of the MGP.
Code of Business Conduct and Ethics. Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a Code of business Conduct and Ethics adopted by Atlas Energy, Inc. and/or that applies to the principal executive officer, principal financial officer and principal accounting officer of the MGP, as well as to persons performing services for the MGP generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the MGP at Atlas Energy, Inc. Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.
We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item 13 “Certain Relationships and Related Party Transactions” for a discussion of compensation paid by us to our MGP.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 2009, we had 1,500 units outstanding. No officer or director of our MGP owns any units. Although, subject to certain conditions, investor partners were able to present their units to us beginning in 2005 for purchase, the MGP is not obligated by the Partnership agreement from purchasing more than 5% of our total outstanding units in any calendar year.
Organizational and Security Ownership of Beneficial Owners. Atlas America owns approximately 100% of the limited liability company interest of Atlas Energy Resources, LLC which owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited liability company interest of the managing general partner. The officers and directors of Atlas America and Atlas Energy Resources LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen and Jeffrey Simmons.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Oil and Gas Revenues. Our MGP is allocated 35.5% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 15% of our subscriptions, its payment of 100% of the tangible costs of drilling and completing our wells and its contribution to us of all of our oil and gas leases. These capital contributions from our MGP totaled $6,256,300. During the years ended December 31, 2009 and 2008, our MGP received $328,900 and $602,100, respectively, from our net production revenues.
Administrative Costs. Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for the administrative costs they incur on our behalf of $75 per well per month, which was proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the years ended December 31, 2009 and 2008, our MGP received $67,100 and $67,900, respectively, for its administrative costs.
Direct Costs. Our MGP and its affiliates are reimbursed by us for all direct costs expended by them on our behalf. During the years ended December 31, 2009 and 2008, our MGP received $224,100 and $153,100, respectively, as reimbursement for direct costs.
Well Charges. Our MGP, as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf and receives well supervision fees for operating and maintaining the wells during producing operations in the amount of $337 per well per month in 2009 and 2008, respectively, subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquired less than 100% of the working interest in a well. For the years ended December 31, 2009 and 2008, our MGP received $301,600 and $305,200, respectively, for well supervision fees.
Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. Transportation rate is 13% of the natural gas sales price. For the years ended December 31, 2009 and 2008, $172,200 and $254,600, respectively, was paid to our MGP for gathering fees. In turn, our MGP paid 100% of these amounts to Atlas America, for the use of its gathering system in transporting a majority of our natural gas production.
Other Compensation. For the years ended December 31, 2009 and 2008, our MGP did not advance any funds to us, or did it provide us with any equipment, supplies or other services.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees. The aggregate fees billed by our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the years ended December 31, 2009 and 2008 and for the reviews of the financial statements included in our Quarterly Reports on Form 10-Q during such years were $31,600 and $30,800, respectively.
Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Auditor. Pursuant to its charter, the audit committee of our MGP is responsible for reviewing and approving, in advance, any audit and any permissible non-audit engagement or relationship between us and our independent auditors. We do not have a separate audit committee.
PART IV
EXHIBIT INDEX
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Atlas America Public #9 Ltd.
Atlas Resources, LLC, Managing General Partner
Date: March 30, 2010 By: /s/ Freddie M. Kotek
Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the
Exchange Act by Non-reporting Issuers
An annual report will be furnished to security holders subsequent to the filing of this report.