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EX-99.1 - EXHIBIT 99.1 - Atlas Resources Public #18-2009 (B) L.P.c98508exv99w1.htm
EX-32.2 - EXHIBIT 32.2 - Atlas Resources Public #18-2009 (B) L.P.c98508exv32w2.htm
EX-32.1 - EXHIBIT 32.1 - Atlas Resources Public #18-2009 (B) L.P.c98508exv32w1.htm
EX-31.1 - EXHIBIT 31.1 - Atlas Resources Public #18-2009 (B) L.P.c98508exv31w1.htm
EX-23.1 - EXHIBIT 23.1 - Atlas Resources Public #18-2009 (B) L.P.c98508exv23w1.htm
EX-31.2 - EXHIBIT 31.2 - Atlas Resources Public #18-2009 (B) L.P.c98508exv31w2.htm
Table of Contents

 
 
United States
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
Commission file number 333-150925-02
ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
(Exact name of registrant as specified in its charter)
     
Delaware
(State or other jurisdiction of
Incorporation or organization)
  26-3223040
(I.R.S. Employer
Identification No.)
     
Westpointe Corporate Center One    
1550 Coraopolis Heights Road, 2nd Floor    
Moon Township, PA
(Address of principal executive offices)
  15108
(Zip Code)
Registrant’s telephone number (412) 262-2830
Securities registered under Section 12(b) of the Exchange Act.
     
Title of each class   Name of each exchange on which registered
None   None
Securities registered under Section 12(g) of the Exchange Act: Investor General Partner Units and Limited Partner Units
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer o   Smaller reporting company þ
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
DOCUMENTS INCORPORATED BY REFERENCE: None
 
 

 

 


 

ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO ANNUAL REPORT
ON FORM 10-K
         
    PAGE  
       
 
       
    3-5  
 
       
    5-10  
 
       
    10  
 
       
    10  
 
       
       
 
       
    10  
 
       
    11-14  
 
       
    15-34  
 
       
    34  
 
       
    34-35  
 
       
    35  
 
       
       
 
       
    35-37  
 
       
    38  
 
       
    38  
 
       
    38-39  
 
       
    39  
 
       
       
 
       
    40  
 
       
    41  
 
       
 Exhibit 23.1
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 99.1

 

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The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements.
PART I
ITEM 1.  
DESCRIPTION OF BUSINESS
General. We were formed as a Delaware limited partnership on April 8, 2008 with Atlas Resources, LLC as our Managing General Partner or MGP. Atlas Resources, LLC, is an indirect subsidiary of Atlas Energy, Inc. (NASDAQ: ATLS) or Atlas Energy.
Atlas Energy’s focus is on the development and production of natural gas and oil in the Appalachian Basin, Michigan Basin and Illinois 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 Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc. provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise capital.
We 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 parent company, Atlas Energy, Inc. for administrative services. See Item 11 “Executive Compensation.”
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 agreements. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $23,383,100. We have drilled 85 developmental wells to the Southern Appalachia Shale, Marcellus, Atrim Shale and New Albany geological formations in Pennsylvania, Tennessee, Michigan and Indiana.
Our wells are currently producing natural gas and oil which are our only products. Most of our gas is gathered and delivered to market through Laurel Mountain Midstream, LLC’s gas gathering system, a newly formed joint-venture between Atlas Energy, Inc.’s affiliate Atlas Pipeline Partners L.P. (NYSE: APL) and The Williams Companies Inc. (NYSE: WMB).
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 “Properties” for information concerning our wells.

 

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Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP a monthly well supervision fee of $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. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:
   
well tending, routine maintenance and adjustment;
 
   
reading meters, recording production, pumping, maintaining appropriate books and records; and
 
   
preparation of reports for us and government agencies.
The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a reasonable charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment costs of the well.
Markets and Competition. The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in oil and gas producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2 “Properties.” During 2009, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competition in selling natural gas and oil production.
While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry. See Item 2 “Properties” regarding the marketing of our natural gas and oil.
Governmental Regulation. The energy industry in general is heavily regulated by federal and state authorities, including regulation of production, environmental quality and pollution control. The intent of federal and state regulations generally is to prevent waste, protect rights to produce natural gas and oil between owners in a common reservoir and control contamination of the environment. Failure to comply with regulatory requirements can result in substantial fines and other penalties. The following discussion of the regulation of the United States of America energy industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which our operations may be subject.
Regulation of oil and gas producing activities. State regulatory agencies where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas operations such as ours including supervising the production activities and the transportation of natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in Tennessee are regulated by the Tennessee Department of Environment and Conservation and the Division of Geology, our oil and gas operations in Michigan are regulated by The Michigan Department of Natural Resources and Environment and our oil and gas operations in Indiana are regulated by the Indiana Department of Natural Resources.
Among other things, these regulations involve:
   
new well permit and well registration requirements, procedures and fees;
   
minimum well spacing requirements;
   
restriction on well locations and underground gas storage;
   
certain well site restoration, groundwater protection and safety measures;
   
landowner notification requirements;
   
certain bonding or other security measures;
   
various reporting requirements;
   
well plugging standards and procedures; and
   
broad enforcement powers.

 

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Environmental and Safety Regulation. Under the Comprehensive Environmental Response, Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws relating to the environment, owners and operators of wells producing natural gas or oil can be liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the owners or operators’ liability can extend to pollution costs from situations that occurred prior to their acquisition of the assets. State public utility regulators have either adopted federal standards or promulgated their own safety requirements consistent with the federal regulations.
We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Our producing activities also must comply with various federal, state and local laws not mentioned, including those covering the discharge of materials into the environment, or otherwise relating to the protection of the environment.
Where can you find more information. We file a Form 10-K Annual Report and Form 10-Q Quarterly Reports as well as other non-recurring special purpose reports with the Securities and Exchange Commission. A complete list of our filings is available on the Securities and Exchange Commission’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800- SEC-0330 for further information.
Additionally, our MGP will provide copies of any of these reports to you without charge. Such requests should be made to:
Atlas Resources Public 18-2009 (B) L.P.
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108
ITEM 2.  
DESCRIPTION OF PROPERTIES
Drilling Activity. As of December 31, 2009, we have drilled 85 gross wells. All of our wells drilled were development wells, which represent a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Also, see Item 7 “Management’s Discussion and Analysis of Financial Condition or Plan of Operations” regarding our revenues recognized, costs and expenses we incurred, and our daily production volumes, average sales prices and production cost per equivalent unit during the period indicated.
                                 
    Development Wells  
    Productive(1)     Dry(2)  
Period Ended December 31,   Gross(3)     Net(4)     Gross(3)     Net(4)  
2009
    81.00       55.50       4.00       4.00  
 
     
(1)  
A “productive well” generally refers to a well that is not a dry hole.
 
(2)  
A “dry hole” generally refers to a well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. The term “completion” refers either to the installation of permanent equipment for the production of oil or gas or, in the case of a dry hole, to the reporting of the abandonment of the well to the appropriate regulatory agency.
 
(3)  
A “gross” well is a well in which we have a working interest.
 
(4)  
A “net” well equals the actual working interest we own in one gross well divided by one hundred. For example, a 50% working interest in a well is one gross well, but a .50 net well.

 

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Table of Contents

Summary of Producing Wells. The table below presents the number of producing gross and net wells at December 31, 2009, in which we have a working interest. All wells are located in the Appalachian Basin, Michigan Basin and Illinois Basin.
                 
    Number of Producing Wells  
    Gross     Net  
Gas
    81       55.50  
Production. The following table presents the quantities of natural gas and oil we produced (net to our interest), our average sales price, and our average production (lifting) cost per equivalent unit of production for the period indicated.
                                         
                                    Average  
Period                                   Production Cost  
Ended   Production     Average Sales Price     (Lifting Cost)  
December 31,   Oil (bbls)(1)     Gas (mcf)(1)     per bbl(1)     per mcf(1)     per mcfe(1) (2)  
2009
    1,300       2,898,300     $ 56.18     $ 5.86     $ 1.59  
 
     
(1)  
“Mcf” represents one thousand cubic feet of natural gas. “Mcfe” represents a thousand cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”).
 
(2)  
Lifting costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, insurance and gathering charges.
Natural Gas and Oil Reserve Information. In December 2008, the Securities and Exchange Commission (“SEC”) approved revisions to its oil and gas reporting disclosures by adopting amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective for fiscal years ending on or after December 31, 2009. These new disclosure requirements are referred to as “Modernization of Oil and Gas Reporting” and include provisions that:
   
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
   
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date.
   
Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves.
   
Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty.”
   
Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
   
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required related to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers’ criteria.
We have complied with these disclosure requirements for the period ended December 31, 2009.

 

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The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and natural gas, which, by an analysis of geological and engineering data, can be estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions, operating methods and government regulations (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties. For the period ended December 31, 2009, we based our estimates of proved reserves on the 12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009 and then applied any basis and British Thermal Units (“btu”) differentials specifically applicable to each oil and gas property based on location and pricing details. The following table summarizes the natural gas and oil prices used in the estimation of proved reserves:
         
    December 31,  
    2009  
Natural gas (per mcf)
  $ 3.87  
Oil ( per bbl)
    61.18  
Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The preparation of our natural gas and oil reserve estimates were completed in accordance with our prescribed internal control procedures, which include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. For the year ended December 31, 2009, we retained Wright & Company, a third-party, independent petroleum engineering firm, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report, including the qualifications of the chief technical person responsible for the report, was prepared in accordance with generally accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this Annual Report on Form 10-K. Results of production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by our independent petroleum engineering firm in preparing their reports. The amounts and timing of future operating costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

 

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We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deducted when applicable, operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. The following table presents our reserve information for the previous two years. We base the estimates on operating methods and conditions prevailing as of the dates indicated:
         
    At December 31,  
    2009  
 
       
Natural gas reserves — Proved Reserves (Mcf) (1) (4):
       
Proved developed reserves (2)
    47,356,500  
 
     
Total proved reserves of natural gas
    47,356,500  
 
       
Oil reserves — Proved Reserves (Bbl) (1) (4):
       
Proved developed reserves (2)
    28,600  
 
     
Total proved reserves of oil
    28,600  
 
     
Total proved reserves (Mcfe)
    47,528,100  
 
     
 
       
PV-10 estimate of cash flows of proved reserves (3) (4):
       
Proved developed reserves
  $ 54,568,785  
 
     
Total PV-10 estimate
  $ 54,568,785  
 
     
PV-10 estimate per investor partner unit (5)
  $ 3,111  
 
     
Undiscounted estimate per investor partner unit (5)
  $ 6,953  
 
     
 
     
(1)  
“Proved reserves” generally refers to the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.
 
(2)  
“Proved developed reserves” generally refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.(Does not include natural gas liquid reserves).
 
(3)  
The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually.
 
(4)  
Please see Regulation S-X rule 4-10 for complete definitions of each reserve category.
 
(5)  
This value per $10,000 unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of a unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the partnership agreement.
We have not filed any estimates of our gas and oil reserves with, nor were such estimates included in any reports to, any Federal or foreign governmental agency other than the SEC within the 12 months before the date of this filing.
Title to Properties. We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, our MGP conducts only a perfunctory title examination at the time it acquires a property. Before our MGP commences drilling operations, it conducts an extensive title examination and performs curative work on defects that it deems significant. Our MGP has obtained title examinations for substantially all of our producing properties. No single property represents a material portion of our holdings.

 

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Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the natural gas industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.
Acreage. The table below presents, by state, the estimated acres of developed and undeveloped oil and gas acreage in which we had an interest at December 31, 2009.
                                 
    Developed Acreage     Undeveloped Acreage(3)  
Location   Gross(1)     Net(2)     Gross(1)     Net(2)  
Pennsylvania
    1,382       907       343       149  
Tennessee
    383       288       127       74  
Michigan
    480       480       160       142  
Indiana
    960       865              
 
                       
Total
    3,205       2,540       630       365  
 
                       
 
     
(1)  
A “gross” acre is an acre in which we own a working interest.
 
(2)  
A “net” acre represents the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre.
 
(3)  
“Undeveloped acreage” means those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not the acreage contains proved reserves.
Delivery Commitments. Atlas Energy markets the remainder of its natural gas, which is principally located in the Fayette County, PA area primarily to Colonial Energy, Inc., UGI Energy Services, Inc., Equitable Gas, Interstate Gas Supply, Inc., Eagle Energy Partners, LP and our other third party natural gas purchasers or marketers are generally for a one-year term.
The pricing arrangements with Hess Corporation, UGI Energy Services, Inc. and other third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commissions or NYMEX spot market price. The total price received for our gas is a combination of the monthly NYMEX spot price plus a basis adjustment. For example, the NYMEX spot price is the base price and there is an additional premium paid, because of the location of the gas (the Appalachian Basin, Michigan Basin and Illinois Basin) in relation to the gas market, which is referred to as the “basis.”
Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements with Hess Corporation, UGI Energy Services, Inc. and the other third-party gas purchasers or marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions through those companies. Hess Corporation, UGI Energy Services, Inc. and the other third-party purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements available to us and its other partnerships. The price paid by Hess Corporation, UGI Energy Services, Inc. and any other third-party purchasers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market price. Also, Atlas Energy’s hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to six years in the future. The overall portion of our natural gas portfolio that is hedged changes from time to time.
To assure that all financial instruments will be used solely for hedging price risks and not for speculative purposes, Atlas Energy has established a committee to assure that all financial trading is done in compliance with Atlas Energy’s hedging policies and procedures. Atlas Energy does not intend to contract for positions that it cannot offset with actual production.

 

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We are not required to provide any fixed and determinable quantities of gas under any agreement other than with Hess Corporation, UGI Energy Services, Inc. and the other third-party gas purchasers or marketers.
ITEM 3.  
LEGAL PROCEEDINGS
The Managing General Partner is not aware of any legal proceedings filed against the Partnership.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their collective business. The MGP management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.
ITEM 4.  
(REMOVED AND RESERVED)
None
PART II
ITEM 5.  
MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS
Market Information. There is no established public trading market for our units and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our partnership agreement which requires:
   
our MGP consent;
   
the transfer not result in materially adverse tax consequences to us; and
   
the transfer not violate federal or state securities laws.
An assignee of a unit may become a substituted partner only upon meeting the following conditions:
   
the assignor gives the assignee the right;
   
our 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, 2009, we had 3,241 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 investor partners. During the period ended December 31, 2009, the partnership made no distributions.

 

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ITEM 7.  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS
The following discussion provides information to assist in understanding our financial condition and result of operations. This discussion should be read in conjunction with our financial statements and related notes appearing elsewhere in this report.
General. We were formed as a Delaware limited partnership on April 8, 2008, with Atlas Resources, LLC as our Managing General Partner, or MGP, to drill natural gas developmental wells. Our MGP is Atlas Resources, LLC an indirect subsidiary of Atlas Energy, Inc. (NASDAQ: ATLS) or Atlas Energy. We have no current plans to sell any of our wells and will continue to produce them until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No additional funds will be required for drillings.
Atlas Energy’s focus is on the development and production of natural gas and oil in the Appalachian Basin, Michigan Basin and Illinois 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 Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc. provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise capital.
Results of Operations. Partnership operations began on April 16, 2009. The Partnership’s first wells were turned on-line on June 9, 2009; therefore, no comparative data is available for the year ended December 31, 2008.
The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the period indicated:
         
    Period Ended  
    December 31,  
    2009  
Production revenues (in thousands):
       
Gas
  $ 16,979  
Oil
    75  
 
     
Total
  $ 17,054  
 
       
Production volumes:
       
Gas (mcf/day) (1)
    14,069  
Oil (bbls/day) (1)
    7  
 
     
Total (mcfe/day) (1)
    14,111  
 
       
Average sales price:
       
Gas (per mcf) (1)
  $ 5.86  
Oil (per bbl) (1)
  $ 56.18  
 
       
Average production costs:
       
As a percent of revenues
    27 %
Per mcfe (1)
  $ 1.59  
 
       
Depletion per mcfe
  $ 2.82  
 
     
(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.

 

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Natural Gas Revenues. Our natural gas revenues were $16,978,800 for the period ended December 31, 2009. We expect that our natural gas revenues will increase over the next year, as the wells are on-line for longer period of time and are producing larger volumes of natural gas.
The price we receive for our natural gas is primarily a result of the index-driven agreements with Hess Corporation, UGI Energy Services, Inc. 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 Revenue. We drill wells primarily to produce natural gas rather than oil, but some wells have limited oil production. Our oil revenues were $75,400 for the period ended December 31, 2009. We expect that our oil revenues will increase over the next year, as more wells are put on-line and are producing larger volumes of oil.
Expenses. Production expenses were $4,618,400 for the period ended December 31, 2009.
Depletion expense as a percentage of oil and gas revenues was 48% for the period ended December 31, 2009.
General and administrative expenses were $66,700 for the period ended December 31, 2009. These expenses include outside costs for services as well as the monthly administrative fee charged by our MGP.
Impairment of oil and gas properties for the period ended December 31, 2009 was $14,593,900. 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. As a result of this assessment, an impairment charge was recognized for the period ended December 31, 2009. This charge is based on reserve quantities, future market values and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.
Liquidity and Capital Resources. Cash provided by operating activities was $4,442,700 in the period ended December 31, 2009. This increase was primarily due to net earnings before depletion, impairment and accretion of $12,665,000 and accrued liabilities of $552,800. The increase was partially offset by the accounts receivable affiliate balance of $8,479,500 and the non cash gain in derivative value of $295,600.
Cash provided by financing activities was $122,554,200 for the period ended December 31, 2009. This was due to partners’ capital contribution.
Cash used in investing activities was $122,554,200 during the period ended December 31, 2009. This consisted of oil and gas well drilling contracts paid to MGP.
Our MGP may withhold funds for estimated future plugging and abandonment costs. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow may not at anytime exceed 5% of our total subscriptions, and we will not borrow from third-parties.
We believe future cash flows from operations and amounts available from borrowings from our MGP or its affiliates will be adequate to fund our operations.

 

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Critical Accounting Policies. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include depletion and depreciation, asset impairment, fair value of derivative instruments, and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements included in Item 8, “Financial Statements.” The critical accounting policies and estimates we have identified are discussed below.
Impairment of Long-Lived Assets. The cost of oil and gas properties, less estimated salvage value, is depleted on the units-of-production method and is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. During the period ended December 31, 2009, we recognized impairment charge of $14,593,900 net of an offsetting gain in accumulated other comprehensive income of $295,600.
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.

 

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Reserve Estimates. Our estimates of proved natural gas and oil reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect partnership distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.
Asset Retirement Obligations. On an annual basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our operating assets. We also estimate the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost estimates is difficult as it involves the estimation of many variables such as economic recoveries of reserves, future labor and equipment rates, future inflation rates and a credit adjusted risk free rate. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we and our subsidiaries have estimated, or changes in their estimates or costs, could reduce our gross profit from operations.
Working Interest. Our agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions, (“working interest”). Our MGP is also provided an additional working interest of 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 based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

 

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ITEM 8.  
FINANCIAL STATEMENTS
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 sheet of Atlas Resources Public #18-2009 (B) L.P. (a Delaware Limited Partnership) as of December 31, 2009, and the related statement of operations, comprehensive loss, changes in partners’ capital, and cash flows for the period January 31, 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 audit 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 audit 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 (B) L.P. as of December 31, 2009, and the results of its operations and its cash flows for the period January 31, 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, 2010

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
BALANCE SHEET
DECEMBER 31,
         
    2009  
 
       
ASSETS
       
Current assets:
       
Cash and cash equivalents
  $ 4,442,800  
Accounts receivable — affiliate
    8,479,500  
Short-term hedge receivable due from affiliate
    5,260,100  
 
     
Total current assets
    18,182,400  
 
       
Oil and gas properties, net
    109,215,300  
Long-term hedge receivable due from affiliate
    4,447,400  
 
     
 
  $ 131,845,100  
 
     
 
       
LIABILITIES AND PARTNERS’ CAPITAL
       
Current liabilities:
       
Accrued liabilities
  $ 552,800  
Short-term hedge liability due to affiliate
    64,100  
 
     
Total current liabilities
    616,900  
 
       
Asset retirement obligation
    431,100  
Long-term hedge liability due to affiliate
    685,000  
 
       
Partners’ capital:
       
Managing general partner
    11,088,100  
Investors partners (12,278 units)
    110,361,200  
Accumulated other comprehensive income
    8,662,800  
 
     
Total partners’ capital
    130,112,100  
 
     
 
  $ 131,845,100  
 
     
The accompanying notes are an integral part of these financial statements.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
STATEMENT OF OPERATIONS
FOR THE PERIOD JANUARY 31, 2009 (date of formation) THROUGH
DECEMBER 31, 2009
         
    2009  
REVENUES
       
Natural gas and oil
  $ 17,054,200  
Interest income
    300  
 
     
Total revenues
    17,054,500  
 
       
COST AND EXPENSES
       
Production
    4,618,400  
Depletion
    8,185,900  
Accretion of asset retirement obligation
    12,900  
Impairment of oil and gas properties
    14,593,900  
General and administrative
    66,700  
 
     
Total expenses
    27,477,800  
 
     
Net loss
  $ (10,423,300 )
 
     
 
       
Allocation of net earnings (loss):
       
Managing general partner
  $ 1,769,700  
 
     
Investor partners
  $ (12,193,000 )
 
     
Net loss per investor partnership unit
  $ (993 )
 
     
The accompanying notes are an integral part of these financial statements.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
STATEMENT OF COMPREHENSIVE LOSS
FOR THE PERIOD JANUARY 31, 2009 (date of formation) THROUGH
DECEMBER 31, 2009
         
    2009  
 
Net loss
  $ (10,423,300 )
Other comprehensive income (loss):
       
Unrealized holding gain on hedging contracts
    12,730,900  
Less: reclassification adjustment for gains realized in net earnings
    (4,068,100 )
 
     
Total other comprehensive income
    8,662,800  
 
     
Comprehensive loss
  $ (1,760,500 )
 
     
The accompanying notes are an integral part of these financial statements.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
FOR THE PERIOD JANUARY 31, 2009 (date of formation) THROUGH
DECEMBER 31, 2009
                                 
                    Accumulated        
    Managing             Other        
    General     Investor     Comprehensive        
    Partner     Partners     Income     Total  
 
                               
Balance at January 31, 2009
  $ 100     $     $     $ 100  
 
                               
Partners’ capital contributions:
                               
Cash
          122,554,200             122,554,200  
Syndication and offering costs
    14,064,800                   14,064,800  
Tangible equipment/leasehold costs
    9,318,300                   9,318,300  
 
                       
Total contributions
    23,383,200       122,554,200             145,937,400  
 
                               
Syndication and offering costs, immediately charged to capital
    (14,064,800 )                 (14,064,800 )
 
                       
 
    9,318,400       122,554,200             131,872,600  
 
                               
Participation in revenue and costs and expenses:
                               
Net production revenues
    3,730,700       8,705,100             12,435,800  
Interest income
    100       200             300  
Depletion
    (696,200 )     (7,489,700 )           (8,185,900 )
Impairment of oil and gas properties
    (1,241,100 )     (13,352,800 )           (14,593,900 )
General and administrative
    (20,000 )     (46,700 )           (66,700 )
Accretion of asset retirement obligation
    (3,800 )     (9,100 )           (12,900 )
 
                       
Net earnings (loss)
    1,769,700       (12,193,000 )           (10,423,300 )
 
                               
Other comprehensive income
                8,662,800       8,662,800  
 
                       
 
                               
Balance at December 31, 2009
  $ 11,088,100     $ 110,361,200     $ 8,662,800     $ 130,112,100  
 
                       
The accompanying notes are an integral part of these financial statements.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
STATEMENT OF CASH FLOWS
FOR THE PERIOD JANUARY 31, 2009 (date of formation) THROUGH
DECEMBER 31, 2009
         
    2009  
Cash flows from operating activities:
       
Net loss
  $ (10,423,300 )
Adjustments to reconcile net loss to net cash provided by operating activities:
       
Depletion
    8,185,900  
Accretion of asset retirement obligation
    12,900  
Impairment of oil and gas properties
    14,889,500  
Non cash gain on derivative
    (295,600 )
Increase in accounts receivable-affiliate
    (8,479,500 )
Increase in accrued liabilities
    552,800  
 
     
Net cash provided by operating activities
    4,442,700  
 
       
Cash flows from investing activities:
       
Oil and gas well drilling contracts paid to MGP
    (122,554,200 )
 
     
Net cash used in investing activities
    (122,554,200 )
 
       
Cash flows from financing activities:
       
Initial capital contribution by MGP
    100  
Partners’ capital contributions
    122,554,200  
 
     
Net cash provided by financing activities
    122,554,300  
 
     
 
       
Net increase in cash and cash equivalents
    4,442,800  
Cash and cash equivalents at beginning of period
     
 
     
Cash and cash equivalents at end of period
  $ 4,442,800  
 
     
 
       
Supplemental Schedule of non-cash investing and financing activities:
       
 
       
Assets contributed by the managing general partner:
       
Tangible equipment
  $ 8,150,500  
Lease costs
    1,167,800  
Syndication and offering costs
    14,064,800  
 
     
 
  $ 23,383,100  
 
     
 
       
Asset retirement obligation
  $ 418,200  
 
     
The accompanying notes are an integral part of these financial statements.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009
NOTE 1 — DESCRIPTION OF BUSINESS
Atlas Resources Public 18-2009 (B) L.P. (the “Partnership”) is a Delaware Limited Partnership, which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner (“MGP”) and Operator, and 3,240 Limited Partners or investor general partner depending on their election. As of December 31, 2009, there were investor contributions of $122,554,200. The Partnership was formed on January 31, 2009 to drill and operate gas wells located in Pennsylvania, Tennessee, Michigan and Indiana. Operations began April 16, 2009.
In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company, Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed substantially all of its natural gas and oil assets and its investment partnership management business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc, (NASDAQ: ATLS). Atlas Resources, LLC serves as the Partnership’s MGP.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of significant accounting policies applied in the preparation of the accompanying financial statements follows:
Use of Estimates
The preparation of the Partnership’s financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including the revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. Actual results could differ from those estimates.
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the purchaser’s current creditworthiness, as determined by review of its customers’ credit information. Credit is extended on an unsecured basis to many of its energy customers. At December 31, 2009 the Partnership’s MGP’s credit evaluation indicated that the Partnership had no need for an allowance for possible losses.
Revenue Recognition
The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas and crude oil in which the Partnership has an interest with other producers are recognized on the basis of the Partnership’s percentage ownership of working interest. Generally, the MGP’s sales contracts are based on pricing provisions that are tied to a market index, with certain adjustments based on proximity to gathering and transmission lines and the quality of its natural gas.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Because there are timing differences between the delivery of the Partnership’s natural gas and oil and its receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based on volumetric data from its records and its estimates of the related transportation and compression fees, which are, in turn, based on applicable product prices. The Partnership had unbilled trade receivables of $6,703,000 at December 31, 2009, which are included in Accounts receivable — affiliate on the Partnership’s Balance Sheet.
Fair Value of Financial Instruments
The carrying amounts of 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 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, 2009, the Partnership had $4,443,300 in deposits at one bank of which $4,193,300 was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
Comprehensive Loss
Comprehensive loss includes net loss and all other changes in equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under accounting principles generally accepted in the United States, have not been recognized in the calculation of net income. These changes, other than net loss, are referred to as “other comprehensive loss” and, for the Partnership, include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges.
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 net revenues and expenses until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Properties
The Partnership follows the successful-efforts method of accounting for oil and gas producing activities. Oil and gas properties are recorded at cost. Depletion is determined on a field-by-field basis using the units-of-production method for well and related equipment costs based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of developed producing properties. In addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of the property are capitalized. The Partnership is required to consider estimated salvage value in the calculation of depletion.
         
    December 31,  
    2009  
Oil and gas properties consist of the following at the date indicated:
       
 
Proved properties:
       
Leasehold interests
  $ 1,087,800  
Wells and related equipment
    128,395,300  
 
     
 
    129,483,100  
 
       
Accumulated depletion
    (20,267,800 )
 
     
 
  $ 109,215,300  
 
     
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. As a result of retirements, the Partnership reclassified $2,807,600 from oil and gas properties to accumulated depletion for the year ended December 31, 2009. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the Statement of Operations.
The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows. The review is done by determining if the historical cost of proved properties less the applicable accumulated depletion and salvage value is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The fair market value is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009. During 2009, the Partnership recognized an impairment charge of $14,593,900, net an offsetting gain in other comprehensive income of $295,600.
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 9). 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.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
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 period ended December 31, 2009, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.
Major Customers
The Partnership’s natural gas is sold under contract to various purchasers. For the period ended December 31, 2009, sales to Equitable Gas, Sequent Energy, Colonial Energy, Inc. and Conoco Phillips Company accounted for 31%, 21% 14% and 13%, respectively, of total revenues. No other customers accounted for 10% or more of total revenues for the period ended December 31, 2009.
Income Taxes
The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account their pro rata share of all items of partnership income and deductions in computing their federal income tax liability.
Recently Adopted Accounting Standards
In February 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-09 “Amendments to Certain Recognition and Disclosure Requirements” (“Update 2010-09”). Update 2010-09 amends Accounting Standards Codification (“ASC”) 855-10-50-1 to clarify that all entities other than SEC filers must disclose (1) the date through, which subsequent events have been evaluated and (2) whether that date is the date the financial statements were issued or available to be issued. However, the date-disclosure exemption for SEC filers does not relieve management from its responsibility to evaluate subsequent events through the date on which financial statements are issued. The Partnership adopted the requirements of Update 2010-09 on December 31, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Extractive Activities Oil and Gas (Topic 932) — Oil and Gas Reserve Estimation and Disclosures” (“Update 2010-03”). Update 2010-03 includes amendments to ASC Topic 932 “Extractive Activities — Oil and Gas,” to include within the ASC the reporting requirements covered in the Securities and Exchange Commission’s (“SEC”) final rule, “Modernization of Oil and Gas Reporting” issued on December 31, 2008. The Partnership adopted the requirements of Update 2010-03 on December 31, 2009. These new disclosure requirements include provisions that:
   
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations;
 
   
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end pricing. This should maximize the comparability of reserve estimates among companies and mitigate the distortion of the estimates that arises when using a single pricing date;
 
   
Permit companies to disclose their probable and possible reserves on a voluntary basis. Current rules limit disclosure to only proved reserves;
 
   
Update and revise reserve definitions to reflect changes in the oil and gas industry and new technologies. New updated definitions include “by geographic area” and “reasonable certainty”;
 
   
Permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and
 
   
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures are required with regard to internal controls over reserve estimation, as well as a report addressing the independence and qualifications of a company’s reserves preparer or auditor based on Society of Petroleum Engineers criteria.
The Partnership has complied with the disclosure requirements for the period ended December 31, 2009.
In August 2009, the FASB issued Accounting Standards Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value” (“Update 2009-05”). Update 2009-05 amends Subtopic 820-10, “Fair Value Measurements and Disclosures — Overall” and provides clarification for the fair value measurement of liabilities in circumstances where quoted prices for an identical liability in an active market are not available. The amendments also provide clarification for not requiring the reporting entity to include separate inputs or adjustments to other inputs relating to the existence of a restriction that prevents the transfer of a liability when estimating the fair value of a liability. Additionally, these amendments clarify that both the quoted price in an active market for an identical liability at the measurement date and the quoted price for an identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are considered Level 1 fair value measurements. These requirements are effective for financial statements issued after the release of Update 2009-05. The Partnership adopted the requirements of Update 2009-05 on September 30, 2009, and it did not have a material impact on its financial position, results of operations or related disclosures.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
In June 2009, the FASB issued Accounting Standards Update 2009-01, “Topic 105 — Generally Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“Update 2009-01”). Update 2009-01 establishes the FASB ASC as the single source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange Commission accounting and reporting standards. Following the ASC, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC. The ASC is effective for financial statements issued for interim and annual periods ending after September 15, 2009. All required references to non-SEC accounting standards have been modified by the Partnership. The Partnership adopted the requirements of Update 2009-01 for its financial statements on September 30, 2009, and it did not have a material impact on its financial statement disclosures.
In May 2009, the FASB issued ASC 855-10, “Subsequent Events” (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The provisions require management of a reporting entity to evaluate events or transactions that may occur after the balance sheet date for potential recognition or disclosure in the financial statements and provides guidance for disclosures that an entity should make about those events. ASC 855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009, and it did not have a material impact on its financial position or results of operations or related disclosures. The adoption of these provisions does not change the Partnership’s current practices with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“ASC 820-10-65-4”). ASC 820-10-65-4 applies to all fair value measurements and provides additional clarification on estimating fair value when the market activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to disclose a change in valuation technique and related inputs to the valuation calculation and to quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.
In April 2009, the FASB issued ASC 825-10-65-1, “Interim Disclosures about Fair Value of Financial Instruments” (“ASC 825-10-65-1”), which requires an entity to provide disclosures about fair value of financial instruments in interim financial information. In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Partnership adopted these requirements on April 1, 2009, and its adoption did not have a material impact on its financial position and results of operations.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 3 — PARTICIPATION IN REVENUES AND COSTS
The MGP and the other partners will generally participate in revenues and costs in the following manner:
                 
    Managing        
    General     Other  
    Partner     Partners(3)  
Organization and offering costs
    100 %     0 %
Lease costs
    100 %     0 %
Revenues (1)
    30 %     70 %
Operating costs, administrative costs, direct costs and all other operating costs (2)
    30 %     70 %
Intangible drilling costs
    0 %     100 %
Tangible equipment costs
    60 %     40 %
 
     
(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. The MGP revenue percentage which may not exceed 40%.
 
(2)  
These costs will be charged to the partners in the same ratio as the related production revenues are credited.
 
(3)  
Other Partners include both investor limited partners and investor general partners. General Partner units can be converted limited partner units when all wells have been drilled and completed. Thereafter, the investor general partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his or her interest in the partnership.
NOTE 4 — CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The Partnership has entered into the following significant transactions with its MGP and its affiliates as provided under the Partnership agreement. The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the Partnership’s Balance Sheet represents the net production revenues due from the MGP.
   
Drilling contracts to drill and complete wells for the Partnership are charged at cost plus 18%. The cost of the wells includes reimbursement to the Partnership’s MGP of its general and administrative overhead cost and all ordinary and actual costs of drilling, testing and completing the wells.
   
The Partnership’s MGP contributed undeveloped leases necessary to cover each of the Partnership’s prospects and as of December 31, 2009 received a credit to its capital account in the Partnership of $1,167,800.
   
Administrative costs which are included in general and administrative expenses in the Partnership’s Statement of Operations are payable at $75 per well, per month. Administrative costs incurred in 2009 were $15,000.
   
Monthly well supervision fees which are included in production expenses in the Partnerships Statement of Operations are payable at $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 for operating and maintaining the wells. Well supervision fees incurred in 2009 were $188,200.
   
Transportation fees which are included in production expenses in the Partnerships Statement of Operations are generally payable at 13% of the natural gas sales price. Transportation fees incurred in 2009 were $2,130,100.
   
Direct costs which are included in production and general administrative expenses in the Partnership’s Statement of Operations are payable to the MGP and its affiliates as reimbursement for all costs expended on the Partnership’s behalf. Direct costs incurred in 2009 were $2,351,800.
 
   
Assets contributed from the MGP which are disclosed on the Partnership’s Statement of Cash Flows as non-cash investing and financing activities for the period ended December 31, 2009 were $23,383,100.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 5 — 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.
NOTE 6 — SUBORDINATION BY MANAGING GENERAL PARTNER
Under the terms of the Partnership agreement, the MGP may be required to subordinate up to 50% of its share of net production revenues of the Partnership to provide a distribution to the investor partners equal to at least 10% of their agreed subscriptions. Subordination is determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of revenues to the investor partners.
NOTE 7 — DERIVATIVE INSTRUMENTS
The MGP on behalf of the Partnership uses a number of different derivative instruments, principally swaps and collars, in connection with its commodity price risk management activities. The MGP enters into financial instruments to hedge the Partnership’s forecasted natural gas 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 Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right, but not obligation, to purchase or sell natural gas, and crude oil at a fixed price for the relevant contract period.
The MGP formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy for undertaking the hedging transactions. This includes matching the commodity derivative contracts to the forecasted transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis, whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of adequate correlation between the hedging instrument and the underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative and subsequent changes in the derivative fair value, which is determined by the MGP through the utilization of market data, will be recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations. For derivatives qualifying as hedges, the Partnership recognizes the effective portion of changes in fair value in partners capital as accumulated other comprehensive loss and will reclassify commodity derivatives to gas and oil production revenues in the Partnership’s Statements of Operations as the underlying transactions are settled. For non-qualifying derivatives and for the ineffective portion of qualifying derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market derivatives in its statements of operations as they occur. The following table summarizes the fair value of derivative instruments as of December 31, 2009.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)
                                 
    Asset Derivatives     Liability Derivatives  
Derivatives in           Fair Value             Fair Value  
Cash Flow   Balance Sheet     December 31,     Balance Sheet     December 31,  
Hedging Relationships   Location     2009     Location     2009  
 
                               
Commodity contracts:
  Current assets   $ 5,260,100     Current liabilities     $ (64,100 )
 
  Long-term assets     4,447,400     Long-term liabilities       (685,000 )
 
                           
 
                               
Total derivatives
          $ 9,707,500             $ (749,100 )
 
                           
Effects of Derivative Instruments on Statement of Operations:
                         
    Gain             Gain  
    Recognized in OCI             Reclassified from OCI  
    on Derivative     Location of Gain/(Loss)     into Income  
    (Effective Portion)     Reclassified from     (Effective Portion)  
Derivatives in   Period Ended     Accumulated     Period Ended  
Cash Flow   December 31,     OCI into Income     December 31,  
Hedging Relationships   2009     (Effective Portion)     2009  
 
                       
Commodity contracts
  $ 12,730,900     Natural gas and oil revenue     $ 4,068,100  
 
                   
At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures, options contracts, and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. Oil contracts are based on a West Texas Intermediate (“WTI”) index. These contracts have qualified and been designated as cash flow hedges and recorded at their fair values.
At December 31, 2009, the Partnership reflected a net hedge asset on its Balance Sheet of $8,958,400. Unrealized gains of $295,600 were recognized in net income that were related to impairment charges of oil and gas properties for the period ended December 31, 2009, which results in a net unrealized gain of $8,662,800. Of the $8,662,800 net gain in accumulated other comprehensive income at December 31, 2009, if the fair values of the instruments remain at current market values, the Partnership will reclassify $5,032,200 of net gains to its Statements of Operations over the next twelve month period as these contracts expire, and $3,630,600 of net gains later periods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge contract is open and may increase or decrease until settlement of the contract. The Partnership recognized no gains or losses during the period ended December 31, 2009, for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)
As of December 31, 2009, Atlas Energy had allocated to the Partnership the following natural gas and oil volumes hedged:
Natural Gas Fixed Price Swaps
                         
Production           Average        
Period Ending   Volumes     Fixed Price     Fair Value  
December 31,   (MMbtu)(1)     (per MMbtu)(1)     Asset (2)  
 
                       
2010
    3,036,400     $ 7.34     $ 4,659,500  
2011
    1,576,000       6.98       1,417,200  
2012
    1,315,200       7.22       1,075,700  
2013
    758,800       7.08       304,600  
 
                     
 
                  $ 7,457,000  
 
                     
Natural Gas Costless Collars
                             
Production               Average        
Period Ending   Option   Volumes     Floor & Cap     Fair Value  
December 31,   Type   (MMbtu)(1)     (per MMbtu)(1)     Asset (2)  
 
                           
2010
  Puts purchased     213,200     $ 7.84     $ 518,600  
2010
  Calls sold     213,200       9.01        
2011
  Puts purchased     955,900       6.45       602,100  
2011
  Calls sold     955,900       7.63        
2012
  Puts purchased     478,400       6.51       224,300  
2012
  Calls sold     478,400       7.71        
2013
  Puts purchased     440,900       6.58       134,800  
2013
  Calls sold     440,900       7.79        
 
                         
 
                      $ 1,479,800  
 
                         
Crude Oil Fixed Price Swaps
                         
Production           Average        
Period Ending   Volumes     Fixed Price     Fair Value  
December 31,   (Bbl)(1)     (per Bbl)(1)     Asset (3)  
 
                       
2010
    800     $ 97.40     $ 13,400  
2011
    700       77.46       2,400  
2012
    500       76.86       500  
2013
    200       77.36       100  
 
                     
 
                  $ 16,400  
 
                     

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 7 — DERIVATIVE INSTRUMENTS (Continued)
Crude Oil Costless Collars
                             
Production               Average        
Period Ending   Option   Volumes     Floor & Cap     Fair Value  
December 31,   Type   (Bbl)(1)     (per Bbl)(1)     Asset (Liability)(3)  
 
                           
2010
  Puts purchased     500     $ 85.00     $ 4,400  
2010
  Calls sold     500       112.92        
2011
  Puts purchased     500       67.22       800  
2011
  Calls sold     500       89.44        
2012
  Puts purchased     300       65.51       100  
2012
  Calls sold     300       91.45        
2013
  Puts purchased     100       65.36        
2013
  Calls sold     100       93.44       (100 )
 
                         
 
                      $ 5,200  
 
                         
 
                           
 
              Total Net Asset     $ 8,958,400  
 
                         
 
     
(1)  
MMBTU represents million British Thermal Units. Bbl represents barrels.
 
(2)  
Fair value based on forward NYMEX natural gas prices.
 
(3)  
Fair value based on forward WTI crude oil prices.
NOTE 8 — FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value.
  Level 1—   Unadjusted quoted prices in active markets for identical assets and liabilities that the reporting entity has the ability to access at the measurement date.
  Level 2—   Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
  Level 3—   Unobservable inputs that reflect the entities own assumptions about the assumptions that market participants would use in the pricing of the asset or liability and are consequently not based on market activity, but rather through particular valuation techniques.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 8 — FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a fair value methodology to value the assets and liabilities for its outstanding derivative contracts (see Note 7). The Partnership’s derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements. Assets and Liabilities measured at fair value at December 31, 2009 were as follows.
                 
    December 31, 2009  
    Level 2     Total  
 
               
Commodity-based derivatives
  $ 8,958,400     $ 8,958,400  
 
           
Total
  $ 8,958,400     $ 8,958,400  
 
           
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The Partnership estimates the fair value of asset retirement obligations, using Level 3 inputs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors at the date of establishment of an asset retirement obligation such as: amount and timing of settlements; the risk-free rate of the Partnership; and estimated inflation rates (see Note 9).
The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the carrying value exceeds such undiscounted cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets. The fair market value using Level 3 inputs is determined as the present value of future net revenues from the production of proved reserves discounted using an annual discount rate of 12% in 2009 and 2008 (see Note 2).

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 9 — ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil and gas wells. The associated asset retirement costs are capitalized as part of oil and gas properties. The Partnership also considers the estimated salvage value in the calculation of depletion.
The estimated liability is based on the MGP’s historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed risk free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations.
A reconciliation of the Partnership’s liability for plugging and abandonment costs for the years indicated are:
         
    Period Ended  
    December 31,  
    2009  
Asset retirement obligation at beginning of period
     
Liabilities incurred from drilling wells
    418,200  
Accretion expense
    12,900  
 
     
Asset retirement obligation at end of period
    431,100  
 
     
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:
         
    December 31,  
    2009  
Leasehold interest
  $ 1,087,800  
Wells and related equipment
    128,395,300  
Accumulated depletion
    (20,267,800 )
 
     
Net capitalized cost
  $ 109,215,300  
 
     
   
(2) 
Oil and Gas Reserve Information
In accordance with the modernization of oil and gas accounting (see Note 2), the Partnership changed its calculation of proved reserves. Under the current accounting literature, the proved reserves quantities and future net cash flows are estimated using a 12-month average pricing at December 31, 2009 based on the prices on the first day of each month. Using this calculation resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end prices as required by the previous rules.

 

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ATLAS RESOURCES PUBLIC 18-2009 (B) L.P.
NOTES TO FINANCIAL STATEMENTS — (Continued)
DECEMBER 31, 2009
NOTE 10 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
The preparation of the Company’s natural gas and oil reserve estimates were completed in accordance with its prescribed internal control procedures, which include verification of input data delivered to its third-party reserve specialist, as well as a multi-functional management review. For the period ended December 31, 2009, the Company retained Wright & Company, independent, third-party reserves engineers, to prepare a report of proved reserves. The reserves report included a detailed review of our properties. Wright & Company’s evaluation was based on more than 35 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations applicable as of December 31, 2009. The Wright & Company report was prepared in accordance with generally accepted petroleum engineering and evaluation principles.
The reserve disclosures that follow reflect estimates of proved reserves consisting of proved developed, net to the Partnership’s interests, of natural gas, crude oil, condensate and NGLs owned at year end and changes in proved reserves during the previous two years. Proved developed reserves are those proved reserves, which can be expected to be recovered from existing wells with existing equipment and operating methods.
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.
                 
    Natural Gas     Oil  
    (Mcf)     (Bbls)  
Proved developed reserves:
               
Beginning of period
           
Extensions, discoveries and other additions
    50,254,800       29,900  
Production
    (2,898,300 )     (1,300 )
 
           
Balance December 31, 2009
    47,356,500       28,600  
 
           
ITEM 9.  
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE:
None.
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.

 

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Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, concluded that, as of December 31, 2009, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including our Chairman of the Board of Directors, Chief Executive Officer, President and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.
Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting as of December 31, 2009 was effective.
This annual report does not include an attestation report by the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.
ITEM 9B.  
OTHER INFORMATION
None.
PART III
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:
             
NAME   AGE   POSITION OR OFFICE
 
           
Freddie M. Kotek
    54     Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas
    50     Executive Vice President — Land and Geology and a Director
Jeffrey C. Simmons
    51     Executive Vice President — Operations and a Director
Jack L. Hollander
    53     Senior Vice President — Direct Participation Programs
Sean P. McGrath
    38     Chief Accounting Officer
Matthew A. Jones
    48     Chief Financial Officer

 

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With respect to the biographical information set forth below:
   
the approximate amount of an individual’s professional time devoted to the business and affairs of our MGP and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and
   
for those individuals who also hold senior positions with other affiliates of our MGP, if it is stated that they devote approximately 100% of their professional time to our MGP and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between our MGP and Atlas America as compared with the other affiliates of our MGP, such as Viking Resources or Resource Energy.
Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since September 2001 and has served as an Executive Vice President since October 2009. He has also served as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004... Kotek will devote approximately 95% of his professional time to the business and affairs of the MGP and Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.
Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served as Vice President of Land and Geology for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the MGP. Mr. Carolas is a certified petroleum geologist and has been with the MGP and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas America, and the remainder of his professional time to the business and affairs of the MGP’s other affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.

 

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Jack L. Hollander. Senior Vice President — Direct Participation Programs since January 2002 and before that he served as Vice President — Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President — Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, and the Chairman of the Investment Program Association which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Sean P. McGrath has been our Chief Accounting Officer and the Chief Accounting Officer of Atlas Energy Resources since December 2008. Mr. McGrath served as the Chief Accounting Officer of Atlas Pipeline Holdings GP from January 2006 until November 2009 and as the Chief Accounting Officer of Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant Controller of Asplundh Tree Expert Co., a utility services and vegetation management company. Mr. McGrath is a Certified Public Accountant. Mr. McGrath will devote approximately 70% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates.
Matthew A. Jones has been our Chief Financial Officer since March 2005 and an Executive Vice President since October 2009. Mr. Jones has been the Chief Financial Officer of Atlas Energy Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief Financial Officer of Atlas Pipeline Holdings GP from January 2006 until September 2009 as the Chief Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005, Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as Managing Director. Mr. Jones worked in Friedman Billings Ramsey’s Energy Investment Banking Group from 1999 to 2005, and in Friedman Billings Ramsey’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones has served as a director of Atlas Pipeline Holdings GP since February 2006. Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. and the remainder of his professional time to the business and affairs of the MGP’s other affiliates.
Audit Committee Financial Expert. The Board of Directors of our MGP acts as the audit committee. The Board of Directors has determined that Freddie M. Kotek, Chairman and President of the MGP meets the requirement of an “audit committee financial expert.” He is not independent.
Remuneration of Officers and Directors. No officer or director of the MGP will receive any direct remuneration or other compensation from the Partnership. These persons will receive compensation solely from affiliated companies of the MGP.
Code of Business Conduct and Ethics. Because the Partnership does not directly employ any persons, the MGP has determined that the partnership will rely on a Code of business Conduct and Ethics adopted by Atlas Energy, Inc. and/or Atlas Energy Resources, LLC 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 Resources, LLC, Westpointe Corporate Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.

 

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ITEM 11.  
EXECUTIVE COMPENSATION
We have no employees and rely on the employees of our MGP and its affiliates for all services. No officer or director of our MGP will receive any direct remuneration or other compensation from us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item 13 “Certain Relationships and Related Party Transactions” for a discussion of compensation paid by us to our MGP.
ITEM 12.  
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 2009, 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.
Organizational and Security Ownership of Beneficial Owners. Atlas Energy, Inc., owns approximately 100% of the limited liability company interest of Atlas Energy Resources, LLC which owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited liability company interest of the MGP. The officers and directors of Atlas America and Atlas Energy Resources, LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen, and Jeffrey Simmons.
ITEM 13.  
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Oil and Gas Revenues. Our MGP is allocated 30% of our oil and gas revenues in return for its payment and/or contribution of services towards our syndication and offering costs equal to 11.48% of our subscriptions, its payment of 60% 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 $23,383,100. During the period ended December 31, 2009, our MGP received $3,730,700 for 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 85 undeveloped prospects for the wells we drilled and received a credit to its capital account in the amount of $1,167,800.
Administrative Costs. Our MGP and its affiliates receive an unaccountable, fixed fee reimbursement for their administrative costs of $75 per well per month, which is proportionately reduced if we acquire less than 100% of the working interest in a well. During the period ended December 31, 2009, our MGP received $15,000 for its administrative costs.
Direct Costs. Our MGP and its affiliates are reimbursed for all direct costs expended on our behalf. During the year ended December 31, 2009 our MGP received $2,351,800 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 approximately 85 gross wells on our behalf. The total amount received by our MGP for drilling and completing the wells was $122,554,200 for the period ended December 31, 2009.
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 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 period ended December 31, 2009, our MGP received $188,200, for well supervision fees.

 

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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 $14,158,952.
Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of our natural gas transported. Transportation rate is 13% of the natural gas sales price. For the period ended December 31, 2009, $2,130,100 was paid to our MGP for gathering fees. In turn, our MGP paid 100% of this amount to Laurel Mountain, for the use of its gathering system in transporting a majority of our natural gas production.
Other Compensation. For the period ended December 31, 2009, our MGP did not advance any funds to us, or did they provide us with any equipment, supplies or other services.
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 period ended December 31, 2009 were $12,400.
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.

 

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PART IV
ITEM 15.  
EXHIBITS
EXHIBIT INDEX
         
    Description   Location
 
       
4(a)
  Certificate of Limited Partnership for Atlas Resources Public 18-2009 (B) L.P.   Previously filed in our Form S-1/A on October 10, 2007
 
       
4(b)
  Amended and Restated Certificate and Agreement of Limited Partnership for Atlas Resources Public 18-2009 (B) L.P.   Previously filed in our Form S-1/A on October 10, 2007
 
       
4(c)
  Drilling and Operating Agreement for Atlas Resources Public 18-2009 (B) L.P.   Previously filed in our Form S-1/A on October 10, 2007
 
       
23.1
  Consent of Wright and Company, Inc.    
 
       
31.1
  Rule 13a-14(a)/15(d) — 14 (a) Certification    
 
       
31.2
  Rule 13a-14(a)/15(d) — 14 (a) Certification.    
 
       
32.1
  Section 1350 Certification.    
 
       
32.2
  Section 1350 Certification.    
 
       
99.1
  Summary Reserve Report    
 
     
(1)  
Filed on October 15, 2008 in the Form S-1A Registration Statement dated October 15, 2008, File No. 333-150925-02

 

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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 (B) L.P.
         
Date: March 30, 2010  Atlas Resources, LLC, Managing General Partner
 
 
  By:   /s/ Freddie M. Kotek    
    Freddie M. Kotek, Chairman of the Board of Directors,   
    Chief Executive Officer and President   
 
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
Date: March 30, 2010  By:   /s/ Freddie M. Kotek    
    Freddie M. Kotek, Chairman of the Board of
Directors, Chief Executive Officer and President
 
     
Date: March 30, 2010  By:   /s/ Frank P. Carolas    
    Frank P. Carolas, Executive Vice President — Land and Geology   
       
Date: March 30, 2010  By:   /s/ Jeffrey C. Simmons    
    Jeffrey C. Simmons, Executive Vice President — Operations   
       
Date: March 30, 2010  By:   /s/ Sean P. McGrath    
    Sean McGrath, Chief Accounting Officer   
       
Date: March 30, 2010  By:   /s/ Matthew A. Jones    
    Matthew A. Jones, Chief Financial Officer   
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.

 

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