ITEM 1: BUSINESS
Overview
Atlas Resources Public #18-2009 (B) L.P. (“we, “us”, or “the Partnership”) is a Delaware limited partnership and was formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “the MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE:ARP). ARP is publicly traded master limited partnership and an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests, to finance a portion of its natural gas and oil production activities.
We have drilled and currently operate wells located in Pennsylvania, Tennessee, Michigan and Indiana. We have no employees and rely on our MGP for management, which in turn, relies on its ultimate Parent Company, Atlas Energy L.P., formerly known as Atlas Pipeline Holdings, L.P. (“Atlas Energy”) (NYSE: ATLS) for administrative services. (See Item 11 “Executive Compensation”). In March 2012, Atlas Energy contributed to ARP, substantially all of Atlas Energy’s natural gas and oil development and production assets and it partnership management business, including ownership of our MGP.
On February 17, 2011, Atlas Energy L.P., a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P.(“APL”)(NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development, and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania and Michigan: and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).
After formation, we received total cash subscriptions from investors of $122,554,200, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $27,065,200. We have drilled 84 development wells within the Marcellus Shale, Southern Appalachia Shale, Antrim Shale, and New Albany Shale geological formations in Pennsylvania, Tennessee, Michigan, and Indiana.
Business Strategy
We do not plan to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling (See Item 2
ITEM 2: PROPERTIES
Natural Gas and Oil Reserves
The following tables summarize information regarding our estimated proved natural gas and oil reserves as of December 31, 2012 and 2011. Proved reserves are 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 only by contractual arrangements, but not on escalations based upon future conditions. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc., an independent third-party reserve engineer. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2012 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month within the prior 12-month period, and are listed below as of the dates indicated:
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 and the timing of development expenditures. 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 was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright and Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States, primarily in Indiana, Michigan, Ohio, Pennsylvania, and Tennessee. The independent reserves engineer’s evaluation was based on more than 36 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our Executive Vice President.
Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company, Inc. in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced. You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. 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 and capital costs. 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 deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods:
(1) This value per limited partner 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 the 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.
Productive Wells
The following table sets forth information regarding productive natural gas and oil wells in which we have a working interest as of December 31, 2012. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells.
Developed Acreage
The following table sets forth information about our developed natural gas and oil acreage as of December 31, 2012.
The leases for our developed acreage generally have terms that extend for the life of the wells. We believe that we hold good and indefeasible title to our producing 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, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed 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 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.
ITEM 3:
ITEM 3: LEGAL PROCEEDINGS
We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. (See Note 9 of “Notes to the Financial Statements”).
ITEM 4:
ITEM 4: MINE SAFETY DISCLOSURES (Not applicable)
PART II
ITEM 5:
ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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 MGP consent;
•
the transfer not result in materially adverse tax consequences to us and;
•
the transfer does 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 term 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. As of December 31, 2012 we had 3,259 unit holders.
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. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2012 and 2011 we distributed the following:
ITEM 7:
ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with (“Item 8:
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas Resources Public #18-2009 (B) L.P.
We have audited the accompanying balance sheets of Atlas Resources Public #18-2009 (B) L.P. (a Delaware Limited Partnership) (the “Partnership”) as of December 31, 2012 and 2011, and the related statements of operations, comprehensive income, changes in partners’ capital, and cash flows for the years ended December 31, 2012 and 2011. 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 audits 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 Resources Public #18-2009 (B) L.P. as of December 31, 2012 and 2011, 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
April 1, 2013
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
BALANCE SHEETS
DECEMBER 31,
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2012 AND 2011
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
YEARS ENDED DECEMBER 31, 2012 AND 2011
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2012 AND 2011
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
See accompanying notes to financial statements.
ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2012 AND 2011
NOTE 1 - BASIS OF PRESENTATION
Atlas Resources Public #18-2009 (B), L.P. (the “Partnership”) is a Delaware limited partnership formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or “the MGP”). Atlas Resources is an indirect subsidiary of Atlas Resources Partners (“ARP”) (NYSE: ARP) an independent developer and producer of natural gas, crude oil and natural gas liquids with operations in basins across the United States. The MGP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. ARP’s parent company is Atlas Energy, L.P. (“ATLS”), a publicly traded master-limited partnership (NYSE: ATLS). ARP was formed in October 2011 to own and operate substantially all of ATLS’ exploration and production assets, which were transferred to ARP on March 5, 2012.
On February 17, 2011, ATLS, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general partner of Atlas Pipeline Partners, L.P.(“APL”)(NYSE: APL), completed an acquisition of assets from Atlas Energy, Inc., which included its investment partnership business; its oil and gas exploration, development, and production activities conducted in Tennessee, Indiana, and Colorado, certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania and Michigan and its ownership and management of investments in Lightfoot Capital Partners, L.P. and related entities (the “Transferred Business”).
The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee, Michigan, and Indiana. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, ATLS for administrative services. The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through third-party gas gathering systems. The Partnership does not plan to sell any of the 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.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
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 revenue and expense accruals, depletion and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates. Certain amounts in the prior year’s financial statements have been reclassified to conform to the current year presentation.
Cash Equivalents
The carrying amounts of the Partnership’s cash equivalents approximate fair values because of the short maturities of these instruments. The Partnership considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Receivables
Accounts receivable affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, 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 management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2012 and 2011, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.
Natural Gas and Oil Properties
Natural gas and oil properties are stated at cost. Maintenance and repairs which generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements which generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.
The Partnership follows the successful efforts method of accounting for oil and gas producing activities. Developments costs, whether successful or not, are capitalized. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas.
The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold 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 cost is eliminated 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 depletion within its balance sheets.
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an 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 and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.
During the years ended December 31, 2012 and 2011, the Partnership recognized $48,973,500 and $3,221,300 of asset impairments related to gas and oil properties net of an offsetting gains in accumulated other comprehensive income of $1,060,600 and $117,900, respectively. These impairments related to the carrying amount of these gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2012 and 2011. The estimate of the fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
Derivative Instruments
The MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (see Note 6). The derivative instruments recorded in the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met.
Asset Retirement Obligations
The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (see Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period 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.
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.
The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2012 and 2011.
Environmental Matters
The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s 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. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the year ended December 31, 2012.
Concentration of Credit Risk
The Partnership sells natural gas, crude oil and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2012, the Partnership had one customer that individually accounted for approximately 82% of the Partnership’s natural gas, oil, and NGL combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2011, the Partnership had four customers that individually accounted for approximately 24%, 18%, 16%, and 11% of the Partnership natural gas, oil an NGL combined revenues, excluding the impact of all financial derivative activity.
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, 2012, the Partnership had $438,700 in deposits at one bank of which $188,700 was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
Revenue Recognition
The Partnership generally sells natural gas, crude oil and NGLs at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed 2 business days prior to the commencement of the production month. Revenue and the related accounts receivable are 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, crude oil and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.
The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, 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 and compression 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, 2012 and 2011 of $1,169,800 and $2,161,400, respectively, which were included in accounts receivable within the Partnership’s balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), 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.
Recently Adopted Accounting Standards
In January 2013, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”). Update 2013-1 clarifies that ordinary trade receivables and receivables are not in the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. Specifically, ASU 2011-11 applies only to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria contained in the FASB Accounting Standards Codification (“Codification”) or subject to a master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership adopted the requirements of Update 2013-01 on December 31, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
In August 2012, the FASB issued ASU 2012-03, Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update) (“Update 2012-03”). Update 2012-03 codified amendments and corrections to the ASC for various Securities and Exchange Commission (“SEC”) paragraphs pursuant or related to 1) the issuance of Staff Accounting Bulletin (“SAB”) 114; 2) the SEC’s Final Rule, Technical Amendments to Commission Rules and Forms Related to the FASB’s Accounting Standards Codification, Release No. 3350-9250, 34-65052, and IC-29748 August 8, 2011; 3) ASU 2010-22, Accounting for Various Topics-Technical Corrections to SEC Paragraphs (SEC Update); and 4) other various status sections. The Partnership adopted the requirements of Update 2012-03 on September 30, 2012, and it did not have a material impact on its financial position, results of operations or related disclosures.
In December 2011, the FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“Update 2011-12”). The amendments in this update effectively defer the implementation of the changes made in Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“Update 2011-05”), related to the presentation of reclassification adjustments out of accumulated other comprehensive income. Under Update 2011-05 which was issued by the FASB in June 2011, entities are provided the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. Under each methodology, an entity is required to present each component of net income along with a total net income, each component of other comprehensive income and a total amount for comprehensive income. Update 2011-05 eliminates the option to present the components of other comprehensive income as part of the statement of changes in equity. As a result of Update 2011-12, entities are required to disclose reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect prior to Update 2011-05. All other requirements in Update 2011-05 are not affected by Update 2011-12. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. Accordingly, entities are not required to comply with presentation requirements of Update 2011-05 related to the disclosure of reclassifications out of accumulated other comprehensive income. The Partnership included statements of comprehensive income (loss) within its March 31, 2012 Form 10-Q upon the adoption of these ASUs on January 1, 2012. The adoption had no material impact on the Partnership’s financial condition or results of operations.
In December 2011, the FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosure about Offsetting Assets and Liabilities (“Update 2011-11”). The amendments in this update require an entity to disclose both gross and net information about both financial and derivative instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset on the statement of financial position. An entity shall disclose at the end of a reporting period certain quantitative information separately for assets and liabilities that are within the scope of Update 2011-11, as well as provide a description of the rights of setoff associated with an entity’s recognized assets and recognized liabilities subject to an enforceable master netting arrangement or similar agreement. Entities are required to implement the amendments for interim and annual reporting periods beginning after January 1, 2013 and such amendments shall be applied retrospectively for any period presented that begins before the date of initial application. The Partnership elected to early adopt these requirements and updated its disclosures to meet these requirements effective January 1, 2012 (see Note 6). The adoption had no material impact on the Partnership’s financial position or results of operations.
In May 2011, the FASB issued ASU 2011-04, Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“Update 2011-04”). The amendments in Update 2011-04 revise the wording used to describe many of the requirements for measuring fair value and for disclosing information about fair value measurements in U.S. GAAP. For many of the amendments, the guidance is not necessarily intended to result in a change in the application of the requirements in Topic 820; rather it is intended to clarify the intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. As a result, Update 2011-04 aims to provide common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. These requirements are effective for interim and annual reporting periods beginning after December 15, 2011. The Partnership updated its disclosures to meet these requirements upon the adoption of Update 2011-04 on January 1, 2012 (see Note 7). The adoption had no material impact on the Partnership’s financial position or results of operations.
Recently Issued Accounting Standards
In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) (“Update 2013-02”). Update 2013-02 requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive income if the amount reclassified to net income in its entirety is in the same reporting period as incurred. For other amounts that are not required to be reclassified in their entirety to net income, an entity is required to reference to other disclosures that provide additional detail about those amounts. Entities are required to implement the amendments prospectively for reporting periods beginning after December 15, 2012, with early adoption being permitted. The Partnership will apply the requirements of Update 2013-02 upon its effective date of January 1, 2013, and it does not anticipate it having a material impact on its financial position, results of operations or related disclosures.
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 - PROPERTY, PLANT AND EQUIPMENT
The following is a summary of natural gas and oil properties at the dates indicated:
The Partnership recorded depletion expense on natural gas and oil properties of $7,784,600 and $10,042,400 for the years ended December 31, 2012 and 2011, respectively. 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.
During the years ended December 31, 2012 and 2011, the Partnership recognized $50,034,100 and $3,339,200 of asset impairment, respectively, related to oil and gas properties on its balance sheets. These impairments related to the carrying amount of these oil and gas properties being in excess of the Partnership’s estimate of their fair value at December 31, 2012 and 2011. The estimate of fair value of these oil and gas properties was impacted by, among other factors, the deterioration of natural gas prices at the date of measurement.
NOTE 5 - ASSET RETIREMENT OBLIGATIONS
The Partnership recognized an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities. The Partnership also recognized a liability for its 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 estimated liability was based on the Partnership’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 was discounted using the MGP’s 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 gas and oil properties, the Partnership determined that there were 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 their commodity price risk management activities. Management enters into financial instruments to hedge forecasted commodity 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 commodities are sold. Under commodity-based 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 put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged. Costless collars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. The costless collar eliminates the initial cost of the purchased put, but places a ceiling price for commodity sales being hedged.
The MGP formally documents all relationships between the Partnership’s 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 management of the Partnership through the utilization of market data, will be recognized immediately in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value of derivative instruments as accumulated other comprehensive income and reclassifies the portion relating to commodity derivatives to gas and oil production revenues 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, management recognized changes in fair value within gain on mark-to-market derivatives in the Partnership’s statements of operations as they occur.
The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheet of $418,300 at December 31, 2012, net of monetized gains receivable.
The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s balance sheets for the periods indicated:
The following table summarizes the gain or loss recognized in the Partnership’s statements of operations or accumulated other comprehensive income in the Partnership’s balance sheet for effective derivative instruments for the periods indicated:
The Partnership enters into commodity future option and collar contracts to achieve more predictable cash flows by hedging its exposure to changes in commodity 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 physical delivery of the commodity. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. NGL fixed price swaps are priced based on a WTI crude oil index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
The Partnership recognized gains of $1,612,000 and $4,657,200 for the years ended December 31, 2012 and 2011, respectively, on settled contracts covering commodity production. These gains were included within gas and oil production revenue in the Partnership’s statements of operations. As the underlying prices and terms in the Partnership’s derivative contracts were consistent with the indices used to sell its natural gas and oil, there were no gains or losses recognized during the years ended December 31, 2012 and 2011 for hedge ineffectiveness or as a result of the discontinuance of any cash flow hedges.
At December 31, 2012 the MGP had a secured hedge facility agreement with a syndicate of banks under which the Partnership will have the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its oil and gas properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2012 only the Partnership’s natural gas swaps are included in the secured hedge facility.
At December 31, 2012, the Partnership had the following commodity derivatives:
Natural Gas Fixed Price Swaps
Natural Gas Put Options
(1) “MMBtu” represents million British Thermal Units.
(2) Fair value based on forward NYMEX natural gas prices, as applicable.
Prior to its merger with Chevron on February 17, 2011, Atlas Energy Inc., (AEI) monetized its derivative instruments, including those related to the future natural gas and oil production of the Transferred Business. AEI also monetized derivative instruments which were specifically related to the future natural gas and oil production of the Partnership. At December 31, 2012 and 2011, remaining hedge monetization cash proceeds of $851,800 and $1,562,200 related to the amounts hedged on behalf of the Partnerships’ limited partners were included within accounts receivable monetized gains-affiliate, respectively and $170,300 and $1,020,500 in long term accounts receivable monetized gains-affiliate, respectively, on the Partnership’s balance sheet. The Partnership will allocate the monetization net proceeds to the limited partners based on the natural gas and oil production generated over the period of the original derivative contracts.
During June 2012, the MGP used the undistributed monetized funds to purchase natural gas put options on behalf of the limited partners of the Partnership only. A premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2012, the put premiums were recorded as short-term and long-term payables to affiliate of $71,000 and $215,800, respectively. Furthermore, the short-term put premium liabilities were included in accounts receivable monetized gains-affiliate and the long-term receivable monetized gains-affiliate were included in long-term liability affiliate on the Partnership’s balance sheet. The put premiums included on the Partnership’s balance sheet are allocable to the limited partners only.
Accumulated Other Comprehensive Income (Loss)
As a result of the monetization and the early settlement of natural gas and oil derivative instruments, the put options, swaps, and the unrealized gains recognized in income currently and in prior periods due to natural gas and oil property impairments, the Partnership recorded a net deferred gain on its balance sheet in accumulated other comprehensive income of $24,400 as of December 31, 2012. Included in other comprehensive income are unrealized gains of $1,060,600, $46,800 and $21,800 net of the MGP interest, that were recognized into income as a result of oil and gas property impairments during the years ended December 31, 2012, 2011, and prior periods, respectively. In 2011, the MGP’s portion of the unrealized loss, $54,600, was written-off as part of the terms of the acquisition of the Transferred Business as a non-cash distribution to the MGP. Of the remaining $24,400 of net unrealized gain in accumulated other comprehensive income, the Partnership will reclassify $55,400 of net gains to the Partnership’s statements of operations over the next twelve month period and the remaining losses of $31,000 in later periods.
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. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. 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 market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. 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 assets and liabilities within the same class of nature and risk. These derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.
Information for assets and liabilities measured at fair value at December 31, 2012 and 2011 was as follows:
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
The Partnership’s other current assets and liabilities on its consolidated combined balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1.
The Partnership estimates the fair value of its asset retirement obligations 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. Information for assets and liabilities that were measured at fair value on a nonrecurring basis for the years ended December 31, 2012 and 2011 were as follows:
The Partnership estimates the fair value of its long-lived assets in conjunction with the review of asset for impairment or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions, and judgments regarding such events or circumstances. For the years ended December 31, 2012 and 2011, the Partnership recognized $50,034,100 and $3,339,200 impairment of long-lived assets which were defined as Level 3 fair value measurements, respectively, (see Note 2 - Impairment of Long-Lived Assets).
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.
•
Administrative costs, which are included in general and administrative expenses in the Partnership’s statements of operations, are payable at $75 per well per month. Administrative costs incurred for the years ended December 31, 2012 and 2011 were $42,200 and $43,800, respectively.
•
Monthly well supervision fees, which are included in production expenses in the Partnership’s statements of operations, are payable at $975 per well per month for the Marcellus wells and $1,500 per well per month for New Albany and Antrim Shale wells. For all other wells a fee of $392 is charged per well per month for operating and maintaining the wells. Well supervision fees incurred for the years ended December 31, 2012 and 2011 were $533,600 and $559,000, respectively.
•
Transportation fees, which are included in production expenses in the Partnership’s statements of operations, incurred for the years ended December 31, 2012 and 2011 were $965,000 and $2,072,700, respectively.
•
Direct costs, which are included in production and general administrative expenses in the Partnership’s statements of operations, are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred for the years ended December 31, 2012 and 2011 were $1,668,400 and $1,745,900, respectively.
•
Assets contributed from the MGP, which are disclosed on the Partnership’s statements of cash flows as non-cash investing and financing activities, for the year ended December 31, 2011 were $1,834,300.
•
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 includes 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 so that the limited partners receive a return of 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 (February 2010) and expiring 60 months from that date.
NOTE 9 - COMMITMENTS AND CONTINGENCIES
General Commitments
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, 2012, the MGP has not withheld any such funds.
Legal Proceedings
The Partnership 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.
NOTE 10 - SUBSEQUENT EVENTS
Management has considered for disclosure any material subsequent events through the date the financial statements were issued.
NOTE 11 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserve Information. The preparation of the Partnership’s natural gas and oil reserve estimates was completed in accordance with its prescribed internal control procedures by its reserve engineers. The accompanying reserve information included below is attributable to the reserves of the Partnership and was derived from the reserve reports prepared for Atlas Resources Public #18-2009 (B) L.P annual Form 10-K for the years ended December 31, 2012 and 2011 (see Note 2). For the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves related to the Partnership. The reserve information for the Partnership includes natural gas and oil reserves which are all located in the United States, primarily in Michigan, Indiana, Ohio, Pennsylvania and Tennessee. The independent reserves engineer’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. The Partnership’s internal control procedures include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 14 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by the Partnership’s senior engineering staff and management, with final approval by the Partnership’s Executive Vice President.
The reserve disclosures that follow reflect estimates of proved developed reserves net of royalty interests, of natural gas, crude oil and natural gas liquids owned at year end. Proved developed reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. In accordance with the prevailing accounting literature, the proved reserves quantities and future net cash flows as of December 31, 2012, and 2011 were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2012 and 2011 and, including adjustments related to regional price differentials and energy content.
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 oil and gas reserves included within the Partnership 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 their effects have not been proved.
Reserve quantity information and a reconciliation of changes in proved reserve quantities included within the Partnership are as follows (unaudited):
(1) The change in the 2011 natural gas reserves was due to actual production being less than engineering forecasts. The change in 2012 and 2011 oil reserves is due to changes in engineering forecasts after considering the impact of actual gas production.
(2) The downward revision in natural gas volumes is primarily due to a decline in SEC base pricing from the prior year, a decrease in the positive gas price basis differentials and a decrease in economic lives resulting from increased expenses.
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities of the Partnership during the periods indicated were as follows:
Results of Operations from Oil and Gas Producing Activities. The results of operations related to the Partnership’s oil and gas producing activities during the periods indicated were as follows:
The following schedule presents the standardized measure of estimated discounted future net cash flows relating to the Partnership’s proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2012 and 2011, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to produce the proved reserves based on year-end cost levels and includes the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations:
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 general partner’s Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our general partner’s Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, 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 general partner’s Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2012, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our general partner’s Chief Executive Officer 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.
There have been no changes in our internal control over financial reporting during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
This annual report does not include an attestation report by our registered public accounting firm regarding internal control of financial reporting because such a report is not required pursuant to the rules of the Securities and Exchange Commission.
PART III
ITEM 10:
ITEM 10: DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Our general partner manages our activities. Unitholders do not directly or indirectly participate in our management or operation or have actual or apparent authority to enter into contracts on our behalf or to otherwise bind us.
The following table sets forth information as of February 15, 2013 with respect to those persons who serve as the officers of our general partner:
Sean P. McGrath has served as Chief Financial Officer of our general partner since February 2012. Sean McGrath has served as Chief Financial Officer of Atlas Energy’s general partner since February 2011. Mr. McGrath was Chief Accounting Officer of Atlas Energy, Inc. and Chief Accounting Officer of Atlas Energy Resources, LLC from December 2008 until February 2011. Mr. McGrath served as Chief Accounting Officer of Atlas Energy GP, LLC (which is Atlas Energy’s general partner) 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 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. From 1998 until 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.
Freddie M. Kotek has served as Senior Vice President of our general partner since March 2012. Mr. Kotek has served as Senior Vice President of Atlas Energy’s general partner since February 2011. Mr. Kotek was an Executive Vice President of Atlas Energy, Inc. from February 2004 until February 2011 and served as a director of Atlas Energy, Inc. from September 2001 until February 2004. Mr. Kotek also was Chief Financial Officer of Atlas Energy, Inc. from February 2004 until March 2005. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and Chief Executive Officer and President since January 2002. Mr. Kotek was a Senior Vice President of Resource America, Inc. from 1995 until May 2004 and President of Resource Leasing, Inc., a wholly owned subsidiary of Resource America, Inc., from 1995 until May 2004.
Jeffrey C. Simmons has served as Senior Vice President of Operations of our general partner since March 2012. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Simmons was a director of Atlas America, LLC from January 2002 until February 2004. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004. Mr. Simmons served as Vice President of Operations for Atlas Resources, LLC from July 1999 until December 2000 and for Atlas America, LLC 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.
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 Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Code of Business Conduct and Ethics
Because the Partnership does not directly employ any persons, the MGP has determined that he partnership will rely on a code of business conduct and ethics that applies to the principal executive officer, principal financial officer and principal accounting officer of our general partner, as well as to persons performing services for us generally. We will make a printed copy of our code of ethics available to any limited partner who so requests. Requests for print copies may be directed to us as follows: Atlas Resource Partners, L.P., Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct is also posted, and any waivers we grant thereunder will be posted, on our website at www.atlasresourcepartners.com.
ITEM 11:
ITEM 11: EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Introduction
We do not directly employ any persons to manage or operate our businesses. Instead, all of the persons (including executive officers of our general partner and other personnel) necessary for the management of our business are employed and compensated by Atlas Energy. Pursuant to our partnership agreement, our general partner manages our operations and activities through and its affiliates’ employees (including employees of Atlas Energy and its general partner). No officer or director of our MGP receives any direct renumberation or other compensation from us. (see “Item 13: Certain Relationships and Related 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, 2012, we had 12,278 units outstanding. No officer or director of our MGP owns any units. 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. The MGP is owned 100% by Atlas Resource Partners whose ultimate parent is Atlas Energy.
ITEM 13:
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Our Relationship with Atlas Resource, LLC
Oil and Gas Revenues. Our MGP is allocated 28.09% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 11.52% of our subscriptions, its payment of 28.50% of the tangible costs and 5.27% of intangible 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 $27,065,200. During the years ended December 31, 2012 and 2011, our MGP received $1,113,400 and $3,162,000, respectively, for 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 is proportionately reduced to the extent we acquired less than 100% of the working interest in a well. During the years ended December 31, 2012 and 2011, our MGP received $42,200 and $43,800, respectively, for 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, 2012 and 2011, our MGP was reimbursed $1,668,400 and $1,745,900, respectively, 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 amounts of $975 per well per month for the Marcellus wells and $1,500 per well per month for New Albany wells. For all other wells a fee of $392 is charged per well per month subject to an annual adjustment for inflation. The well supervision fees are proportionately reduced to the extent we acquire less than 100% of the working interest in a well. For the years ended December 31, 2012 and 2011, our MGP received $533,600 and $559,000, 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. For the years ended December 31, 2012 and 2011, $965,000 and $2,072,700, respectively, was paid to our MGP for gathering fees. In turn, our MGP remitted 100% of these amounts to Atlas Energy, who in turn paid LMM for the use of LMM’s gathering system in transporting a majority of our natural gas production.
Other Compensation. For the years ended December 31, 2012 and 2011, 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
For the years ended December 31, 2012 and 2011, the accounting fees and services charged by Grant Thornton, LLP, our independent auditors, were as follows:
Audit Committee Pre-Approval Policies and Procedures
The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2012 and 2011.
PART IV
ITEM 15:
ITEM 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
EXHIBIT INDEX
(1) Filed on October 15, 2008 in the Form S-1/A Registration Statement dated October 15, 2008, File No. 333-150925-02
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities of the Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ATLAS RESOURCES PARTNERS L.P.
BY: ATLAS RESOURCE PARTNERS GP, LLC, ITS GENERAL PARTNER
ATLAS ENERGY L.P.
Date: April 1, 2013
By: /s/ FREDDIE M. KOTEK
Freddie M. Kotek, Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following person on behalf of the registrant and in the capacities and on the dates indicated.
Date: April 1, 2013
By: /s/ SEAN P. MCGRATH
Sean P. McGrath, Chief Financial Officer