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:
•
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 MGP 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 MGP 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, 2010, we had 4,904 unit holders.
Distributions. Our MGP reviews our accounts monthly 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 year ended December 31, 2010, we distributed $4,066,500 and $11,573,900 to our general and limited partners, respectively. During the period ended December 31, 2009, the partnership made no distributions.
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.
We are a Delaware limited partnership, formed on June 9, 2009, with Atlas Resources, LLC serving as our Managing General Partner (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc., (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.
On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets. As part of the transaction, Atlas Resources, LLC became an indirect subsidiary of AHD. Concurrent with the sale of assets by Atlas Energy to AHD, Atlas Energy and its subsidiaries completed a merger transaction with Chevron Corporation (“Chevron”), whereby Chevron acquired the assets of Atlas Energy in exchange for $38.25 per Atlas Energy share. Subsequent to the transaction, AHD changed its name to Atlas Energy, L.P.
Results of Operations. Partnership operations began in September 2009. The Partnership’s first wells were turned on-line in October 2009.
The following table sets forth information relating to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:
(1)
“Mcf” represents thousand cubic feet, “mcfe” represents thousand cubic feet equivalent and “bbls” represents barrels. Bbls are converted to mcfe using the ratio of six mcfs to one bbl.
(2)
The average sales price are calculated by including total revenue and dividing by the total volume for the period.
Natural Gas Revenues. Our natural gas revenues were $38,419,900 and $1,483,100 for the year ended December 31, 2010 and the period ended December 31, 2009, respectively, an increase of $36,936,800. The $36,936,800 increase in natural gas revenues for the year ended December 31, 2010 as compared to the prior year period was attributable to an increase in production volumes. Our production volumes increased to 17,026 mcf per day for the year ended December 31, 2010 from 3,545 mcf per day for the period ended December 31, 2009, an increase of 13,481 mcf per day. The overall increase in natural gas production volumes for the year ended December 31, 2010 as compared to the prior year period ended December 31, 2009 resulted from more wells being online in the current year.
The price we receive for our natural gas is primarily a result of the index-driven agreements with Sequent Energy Management, Equitable Gas, South Jersey Resources, LLC, Colonial Energy 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 $2,600 for the year ended December 31, 2010. There were no oil revenues for the period ended December 31, 2009.
Natural Gas Liquids Revenue. The majority of our wells produce “dry gas,” which is composed primarily of methane and requires no additional processing before being transported and sold to the purchaser. Some wells, however, produce “wet gas,” which contains larger amounts of ethane and other associated hydrocarbons (i.e. “natural gas liquids”) that must be removed prior to transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our natural gas liquids revenues were $2,700 for the year ended December 31, 2010.
Expenses. Production expenses were $11,405,600 and $246,700 for the year ended December 31, 2010 and period ended December 31, 2009, respectively, an increase of $11,158,900. This increase was due to more wells being online in the current year.
Depletion of oil and gas properties as a percentage of oil and gas revenues was 52% and 48% for the year ended December 31, 2010 and period ended December 31, 2009, respectively. These percentage changes are directly attributable to changes in revenues, oil and gas reserve quantities, product prices, production volumes and changes in the depletable cost basis of our oil and gas properties.
Impairment of oil and gas properties for the year ended December 31, 2010 was $34,817,000. Annually, we compare the carrying value of our proved developed oil and gas producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value an impairment charge is recognized. This charge is based on reserve quantities, future market values and our carrying value. We cannot provide any assurance that impairment charges may or may not be taken in future periods.
General and administrative expenses were $148,800 and $42,000 for the year ended December 31, 2010 and period ended December 31, 2009, an increase of $106,800. This increase was due to more wells being online in the current year.
Liquidity and Capital Resources. Cash provided by operating activities was $18,673,100 for the year ended December 31, 2010. This increase was primarily due to an increase of net earnings before depletion, impairment and accretion of $26,258,200 and accrued liabilities of $471,500, partially offset by the change in accounts receivable-affiliate of $7,477,800 and a non-cash gain on derivative value of $578,800.
Cash used in investing activities decreased $135,998,500 to $46,501,500 for the year ended December 31, 2010, from $182,500,000 for the period ended December 31, 2009. This consisted of oil and gas well drilling contracts paid to our MGP.
Cash provided by financing activities was $4,547,200 for the year ended December 31, 2010. These include funds contributed by the investor partners of $20,187,600, less cash distributions to partners of $15,640,400. Cash provided by financing activities was $208,813,800 during the period ended December 31, 2009. This was due to partners’ capital contributions.
Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2010, our MGP had not withheld any funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.
The Partnership is generally limited to the amount of funds generated by the cash flow from our operations, which we believe is adequate to fund future operation and distributions to our partners. Historically, there has been no need to borrow funds from our MGP to fund operations.
Critical Accounting Policies
Use of estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include 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 of America and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. During 2010, we recognized an impairment charge of $34,817,000, net of an offsetting gain in other comprehensive income of $578,800.
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.
Our 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 have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.
Working Interest. Our Partnership 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 10% as provided in our agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. As of December 31, 2010, $48,300 of net earnings resulting from the working interest adjustment was reclassified from our MGP’s capital account to the limited partner’s capital account.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas Resources Public #18-2009 (C) L.P.
We have audited the accompanying balance sheet of Atlas Resources Public #18-2009 (C) L.P. (a Delaware Limited Partnership) as of December 31, 2010 and 2009, and the related statement of operations, comprehensive (loss) income, changes in partners’ capital, and cash flows for the year ended December 31, 2010 and the period June 9, 2009 (date of formation) through December 31, 2009. 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 audit.
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 provides 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 Resources Public #18-2009 (C) L.P. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the year ended December 31, 2010 and the period June 9, 2009 (date of formation) through December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 30, 2011
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
BALANCE SHEETS
DECEMBER 31,
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2010 AND
FOR THE PERIOD JUNE 9, 2009 (date of formation) THROUGH DECEMBER 31, 2009
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
FOR THE YEAR ENDED DECEMBER 31, 2010 AND
FOR THE PERIOD JUNE 9, 2009 (date of formation) THROUGH DECEMBER 31, 2009
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
FOR THE YEAR ENDED DECEMBER 31, 2010 AND
FOR THE PERIOD JUNE 9, 2009 (date of formation) THROUGH DECEMBER 31, 2009
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2010 AND
FOR THE PERIOD JUNE 9, 2009 (date of formation) THROUGH DECEMBER 31, 2009
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2010 AND 2009
NOTE 1 - DESCRIPTION OF BUSINESS
Atlas Resources Public 18-2009 (C) L.P. (the “Partnership”) is a Delaware limited partnership, formed on June 9, 2009 with Atlas Resources, LLC serving as its Managing General Partner and Operator (Atlas Resources or “MGP”). Atlas Resources, LLC is an indirect subsidiary of Atlas Energy, Inc., (“Atlas Energy”) (NASDAQ: ATLS). Atlas Energy’s focus is on the development and/or production of natural gas and oil in the Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America. Atlas Energy is also a leading sponsor of and manages tax-advantaged direct investment partnerships, in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy Resource Services, Inc. provides Atlas Energy with the personnel necessary to manage its assets and raise capital.
On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets. Subsequent to the transaction, AHD changed its name to Atlas Energy, L.P. and assumed control of Atlas Resources.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In management’s opinion, all adjustments necessary for a fair presentation of the Partnership’s financial position, results of operations and cash flows for the periods disclosed have been made. Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
The Partnership’s first year was a short period beginning on June 9, 2009 (date of formation) and ending December 31, 2009. The Partnership began well drilling operations on September 17, 2009 with our wells first production beginning during October 2009.
Use of Estimates
The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.
The natural gas industry principally conducts its business by processing actual transactions as much as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Differences between estimated and actual amounts are recorded in the following month’s financial results. Management believes that the operating results presented for the year ended December 31, 2010 and period ended December 31, 2009 represent actual results in all material respects (see “Revenue Recognition” accounting policy for further description).
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the 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, 2010 the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
Fair Value of Financial Instruments
The carrying amounts of the Partnership’s cash and receivables approximate fair values because of the short maturities of these instruments.
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 year ended December 31, 2010 and period ended December 31, 2009.
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, 2010, the Partnership had $3,204,200 in deposits at one bank, of which $1,700 is insured by the Federal Deposit Insurance Corporation. At December 31, 2009, the Partnership had $26,313,800 at one bank, of which $26,313,800 is insured by the Federal Deposit Insurance Corporation, subject to the Fiduciary account provisions. No losses have been experienced on such investments.
Oil and Gas Properties
Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Oil is converted to gas equivalent basis (“Mcfe”) at the rate of one barrel equals 6 Mcf.
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds to accumulated depreciation and depletion within its balance sheets. As a result of retirements, the Partnership reclassified $739,400 for the year ended December 31, 2010, from oil and gas properties to accumulated depletion.
There was no construction in progress (“CIP”) of oil and gas properties at December 31, 2010. At December 31, 2009, CIP was $122,532,400.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Partnership’s oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.
During the year ended December 31, 2010, the Partnership recognized a $34,817,000 asset impairment related to oil and gas properties, net of an offsetting gain in accumulated other comprehensive income of $578,800. There was no asset impairment recorded for the period ended December 31, 2009. The impairment related to the carrying amount of the oil and gas properties being in excess of its estimate of their fair value at December 31, 2010. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices.
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 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues and expenses based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership. As of December 31, 2010, $48,300 of net earnings resulting from the working interest adjustment was reclassified from the Partnership’s MGP’s capital account to the limited partner’s capital account.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue Recognition
The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation fees which are, in turn, based upon applicable product prices (see “Use of Estimates” accounting policy for further description). The Partnership had unbilled revenues at December 31, 2010 and 2009 of $7,055,900 and $1,249,200, respectively, which are included in accounts receivable - affiliate within the Partnership’s balance sheets.
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 5). 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 year ended December 31, 2010 and period ended December 31, 2009, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income and all other changes in equity of a business during a period from non-owner sources that, under accounting principles generally accepted in the United States of America, have not been recognized in the calculation of net income, these changes, other than net income, are referred to as “other comprehensive income (loss), and for the Partnership include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards
In April 2010, the FASB issued Accounting Standards Update 2010-14, “Accounting for Extractive Industries - Oil & Gas: Amendments to Paragraph 932-10-S99-1” (“Update 2010-14”). Update 2010-14 provides amendments to add the SEC’s Regulation S-X Rule 4-10, “Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conservation Act of 1975” (“S-X Rule 4-10”) to Accounting Standards Codification (“ASC”) Topic 932 “Extractive Activities - Oil and Gas”. S-X Rule 4-10 was included in the SEC’s Final Rule, “Modernization of Oil and Gas Reporting, which became effective January 1, 2010. As Update 2010-14 only served to align the FASB’s ASC Topic 932 with the SEC’s S-X Rule 4-10, its adoption did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.
In February 2010, the FASB issued Accounting Standards Update 2010-09, “Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 removes the requirement for an SEC filer to disclose a date through which subsequent events have been evaluated in both issued and revised financial statements. Revised financial statements include financial statements revised as a result of either correction of an error or retrospective application of U.S. generally accepted accounting standards. The requirements of Update 2010-09 were effective upon its issuance on February 24, 2010. The requirements of Update 2010-09 were applied upon its adoption, and it did not have an impact on the Partnership financial position, results of operations or related disclosures.
In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurement and Disclosures (Topic (820) - Improving Disclosures about Fair Value Measurement” (“Update 2010-06”). Update 2010-06 clarifies and requires new disclosures about the transfer of amounts between Level 1 and Level 2, as well as significant transfers in and out of Level 3. In addition, for Level 2 and Level 3 measurements, Update 2010-06 requires additional disclosure about the valuation technique used or any changes in technique. Update 2010-06 also clarifies that entities must disclose fair value measurements by classes of assets and liabilities, based on the nature and risks of the assets and liabilities. The requirements of Update 2010-06 are effective at the start of a reporting entity’s first fiscal year beginning after December 15, 2009 (January 1, 2010 for the Partnership). The requirements of Update 2010-06 were applied upon its adoption on January 1, 2010 and it did not have a material impact on the Partnership’s financial position, results of operations or related disclosures.
Major Customers
The Partnership’s natural gas is sold under contract to various purchasers. For the year ended December 31, 2010, sales to Sequent Energy Management, Equitable Gas, South Jersey Resources, LLC and Colonial Energy, Inc. accounted for 20%, 18%, 13% and 10%, respectively of total revenues. For the period ended December 31, 2009, sales to Equitable Gas and CIMA Energy, LTD. accounted for 77% and 23%, respectively, of total revenues. No other customers accounted for 10% or more of total revenues for the year ended December 31, 2010 or the period ended December 31, 2009.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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.
NOTE 3 - PARTICIPATION IN REVENUES AND COSTS
The MGP and the limited partners will 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 10% 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 - OIL AND GAS PROPERTIES
The following is a summary of oil and gas properties:
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 5 - ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and related facilities. It also recognizes a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the 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 credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its oil and gas properties, the Partnership has determined that there are no other material retirement obligations associated with tangible long-lived assets.
A reconciliation of the Partnership’s liability for well plugging and abandonment costs for the periods indicated is as follows:
NOTE 6 - DERIVATIVE INSTRUMENTS
The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps, collars and options, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge its forecasted natural gas and crude oil sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas and crude oil is sold. Under swap agreements, the MGP receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas and crude oil at a fixed price for the relevant contract period.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the MGP will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the 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 reclassifies the portion relating to commodity derivatives to gas and oil production revenues for the Partnership’s derivatives within 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.
Derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value. The Partnership reflected a net derivative asset on its balance sheets of $17,141,000 at December 31, 2010, however an unrealized gain of $578,800 recognized in income results in a net accumulated other comprehensive income balance of $16,562,200. The unrealized gain of $578,800 is comprised from the December 31, 2010 impairment. Of the remaining $16,562,200 net unrealized gain in accumulated other comprehensive income at December 31, 2010, if the fair values of the instruments remain at current market values, the Partnership will reclassify $9,004,400 of gains to the Partnership’s statements of operations over the next twelve month period as these contracts expire. Aggregate gains of $7,557,800 will be reclassified to the Partnership’s statements of operations in later periods as these remaining contracts expire. Actual amounts that will be reclassified will vary as a result of future price changes.
The following table summarizes the fair value of the Partnership’s derivative instruments as of December 31, 2010 and the period ended December 31, 2009, as well as the gain or loss recognized in the statements of operations for effective derivative instruments for the year ended December 31, 2010 and period ended December 31, 2009:
Fair Value of Derivative Instruments:
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
Effects of Derivative Instruments on Statement of Operations:
The MGP enters into natural gas and crude oil future option contracts and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in natural gas and oil prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
In December 2010, the MGP, on behalf of the Partnership, allocated approximately $48,800 in net proceeds from the early settlement of natural gas derivative positions for production periods during 2012. The gain realized upon the early terminations of these derivative positions is reported in accumulated other comprehensive income and will be reclassified to the Partnership’s statements of operations in the same periods in which the hedged production revenues would have been recognized in earnings. The $48,800 in net proceeds is recorded in the hedge receivable balance on the Partnership’s balance sheets at December 31, 2010.
As of December 31, 2010, Atlas Energy had allocated to the Partnership the following natural gas volumes hedged:
Natural Gas Fixed Price Swaps
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 6 - DERIVATIVE INSTRUMENTS (Continued)
Natural Gas Costless Collars
(1)
MMBTU represents million British Thermal Units.
(2)
Fair value based on forward NYMEX natural gas prices, as applicable.
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 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 assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership estimates the fair value of asset retirement obligations using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and estimated inflation rates (see Note 5).
NOTE 8 - 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:
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 8 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)
The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership’s balance sheets represents the net production revenues due from the MGP.
Subordination by Managing General Partner
Under the terms of the Partnership Agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to the benefit of the limited partners for an amount equal to at least 10% of their net subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution to the investor partners (August 2010) and expiring 60 months from that date.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
Subject to certain conditions, investor partners may present their interests beginning in 2014 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.
Beginning one year 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 estimated future plugging and abandonment costs. As of December 31, 2010, the MGP has not withheld any such funds.
Legal Proceedings
The Managing General Partner is not aware of any legal proceedings filed against the Partnership.
The Partnership’s MGP is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition or results of operations.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 10 - 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 period indicated:
(2)
Oil and Gas Reserve Information
The preparation of the Partnership’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, 2010, the Partnership 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, 2010. 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.
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.
ATLAS RESOURCES PUBLIC 18-2009 (C) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2010 AND 2009
NOTE 11 - SUBSEQUENT EVENTS
Atlas Energy, Inc. Asset Acquisition
On February 17, 2011, Atlas Pipeline Holdings, L.P. (“AHD”) (NYSE: AHD), a then-majority owned subsidiary of Atlas Energy and parent of the general partner to Atlas Pipeline Partners, L.P. (“APL”) (NYSE: APL), completed an acquisition of assets from Atlas Energy, which included its investment management business, proved reserves located in the Appalachian Basin, New Albany Shale, Antrim Shale, Chattanooga Shale and Niobrara formations, and other assets (“Asset Acquisition”). As part of the transaction, Atlas Resources, LLC became an indirect subsidiary of AHD. Concurrent with the Asset Acquisition, Atlas Energy and its subsidiaries completed a merger transaction with Chevron Corporation (“Chevron”), whereby each share of Atlas Energy was converted into the right to receive $38.25 in cash as well as a pro rata distribution of all AHD common units owned by Atlas Energy, and Atlas Energy became a wholly-owned subsidiary of Chevron (“Merger”). Subsequent to the Merger, AHD changed its name to Atlas Energy, L.P.
Laurel Mountain Sale
Concurrently with the completion of the Asset Acquisition, APL, an affiliate of the MGP, completed its sale to Atlas Energy Resources, LLC of its 49% non-controlling interest in the Laurel Mountain joint venture.
Hedge Monetization
In conjunction with the “Asset Acquisition,” Atlas Energy monetized all derivative contracts related to natural gas and oil production. The Partnership will share in the total available hedge gains with all other Partnerships sponsored by the MGP. Each Partnership will participate in the monetized funds based on its production volumes during the period of the original derivative contracts.
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, 2010, 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, 2010 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 the 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 our 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 Energy 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 Energy, 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 Energy 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 Energy, 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.
Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January 2001. Mr. Simmons has been an Executive Vice President of Atlas Energy since January 2001 and was a Director of Atlas Energy 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 Energy 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 Energy, 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 Energy 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 Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Sean P. McGrath Chief Financial Officer. Mr. McGrath was Chief Accounting Officer of Atlas Energy and Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as Chief Accounting Officer of Atlas Pipeline Holdings GP, LLC from January 2006 until November 2009 and as Chief Accounting Officer of Atlas Pipeline Partners GP, LLC 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 until 2005. Mr. McGrath is a Certified Public Accountant.
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. 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 12
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 2010, we had 22,928.90 units outstanding. Although, subject to certain conditions, investor partners may present their units to us beginning in 2014 for purchase, the MGP is not obligated by the Partnership Agreement to purchase more than 5% of our total outstanding units in any calendar year.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Oil and Gas Revenues. Our MGP is allocated 26% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 10.36% of our subscriptions, its payment of 40% of the tangible costs of drilling and completing our wells and its contributions to us of all of our oil and gas leases for a total capital contribution of $43,449,300. During the year ended December 31, 2010 and period ended December 31, 2009, our MGP received $7,025,100 and $370,900, respectively, of our net production revenues.
Leases. Following the final closing date, for the offering of our units to potential investors, which was December 31, 2009, our MGP contributed oil and gas leases to us covering 130 undeveloped prospects for the wells we drilled and received a credit to its capital account in the amount of $969,900 and $2,248,000 for the year ended December 31, 2010 and the period ended December 31, 2009, respectively.
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 is proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the year ended December 31, 2010 and period ended December 31, 2009, our MGP received $70,500 and $2,600, respectively.
Direct Costs. Our MGP and its affiliates are reimbursed by us for all direct costs expended on our behalf. During the year ended December 31, 2010 and period ended December 31, 2009, we reimbursed our MGP $6,230,700 and $79,800, respectively, for direct costs.
Drilling Contracts. After the initial closing date of the offering of our units to investors, we entered into a drilling contract with our MGP to drill and complete 130 gross wells on our behalf. The total amount received by our MGP for drilling and completing the wells was $229,001,500.
Well Charges. Our MGP, as operator, 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 $975 per well per month for Marcellus wells, $1,500 per well per month for New Albany wells and $600 per well per month for horizontal Antrim Shale wells. For all other wells a fee of $392 is charged per well per month for operating and maintaining the wells. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well. For the year ended December 31, 2010 and period ended December 31, 2009, our MGP received $935,600 and $31,800, respectively, for well supervision fees.
Dealer-Manager Fees. As part of the offering of our units to potential investors, Anthem Securities, Inc. an affiliate of our MGP and the dealer-manager of our initial offering received a 2.5% dealer-manager fee, a 7% sales commission, a .5% reimbursement of marketing expenses, and a .5% reimbursement of the selling agents’ accountable due diligence fees in the amount of $23,718,800.
Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. For the year ended December 31, 2010 and period ended December 31, 2009, $4,317,600 and $174,500 was paid to our MGP for gathering fees. In turn, our MGP paid 100% of this amount to Atlas Energy for the use of its gathering system in transporting a majority of our natural gas production.
Other Compensation. For the year ended December 31, 2010, our MGP did not advance any funds to us, or did they provide us with any equipment, supplies or other services.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees. The aggregate fees recognized by the Partnership from our independent auditors, Grant Thornton LLP, for professional services rendered for the audit of our annual financial statements for the year ended December 31, 2010 and period ended December 31, 2009, and for the reviews of the financial statements included in our quarterly reports on form 10-Q during such years were $33,200 and $9,100, 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 Atlas Energy, Inc. 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 Resources Public 18-2009 (C) L.P.
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.