As filed with the Securities and Exchange Commission on April 30, 2007
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10
GENERAL FORM FOR REGISTRATION OF SECURITIES
Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934
Pursuant to Section 12(b) or (g) of the Securities Exchange Act of 1934
ATLAS AMERICA SERIES 27-2006 L.P.
(Exact Name of registrant as specified in its charter)
| Delaware (State or other jurisdiction of incorporation or organization) | 20-5242075 (I.R.S. Employer Identification Number) |
| 311 Rouser Road Moon Township, Pennsylvania (Address of principal executive offices) | 15108 (Zip Code) |
Registrant’s telephone number, including area code:
(412) 262-2830
Securities to be registered pursuant to Section 12(b) of the Act:
None
Securities to be registered pursuant to Section 12(g) of the Act:
Units(1)
(Title of Class)
| (1) | Units means limited partner units, converted limited partner units and investor general partner units, which will be automatically converted into the converted limited partner units by our managing general partner once all of our wells are drilled and completed. |
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ITEM 1. BUSINESS.
THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS AND FINANCIAL TRENDS THAT MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL POSITION. THESE STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THE RESULTS ANTICIPATED IN THOSE STATEMENTS. THESE RISKS INCLUDE RISKS ASSOCIATED WITH DRILLING AND OPERATING OUR WELLS, MARKETING NATURAL GAS AND OIL PRODUCTION FROM THE WELLS, AND FLUCTUATIONS IN MARKET PRICES FOR THE NATURAL GAS AND OIL PRODUCED FROM THE WELLS. FOR A MORE COMPLETE DISCUSSION OF THE RISKS AND UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE “RISK FACTORS” IN ITEM 1A. THE TERMS “WE,” “OUR”, “US,” “ITS” AND THE “COMPANY” USED IN THIS FORM 10 ARE USED AS REFERENCES TO ATLAS AMERICA SERIES 27-2006 L.P.
General
We were formed as a Delaware limited partnership on July 21, 2006, with Atlas Resources, LLC, a Pennsylvania limited liability company, as our managing general partner. Before March 2006, Atlas Resources, LLC was a Pennsylvania corporation named Atlas Resources, Inc. Our partnership operations began on our first closing on November 6, 2006. When we had our final closing on December 29, 2006, we had 1,359 investors who purchased our Units (our “participants”). “Units” means our limited partner units, our converted limited partner units and our investor general partner units that will automatically be converted by our managing general partner into the converted limited partner units once all of our wells are drilled and completed. In accordance with the terms of our offering, 2,776.079 Units were sold at $25,000 per Unit, 59.321 Units were sold at $23,250 per Unit to selling agents and their registered representatives and principals and clients of a registered investment advisor, no Units were sold to our managing general partner, and its officers, directors and affiliates, and 4.6 Units were sold at $22,125 per Unit to investors who bought Units through the officers and directors of our managing general partner.
Our participants contributed a total of $70,883,000 in subscription proceeds to us, which we paid to our managing general partner serving as our operator and general drilling contractor under our drilling and operating agreement. We used all of our subscription proceeds to drill and complete wells located primarily in western Pennsylvania and central Tennessee as described below. Under our partnership agreement, all of the subscription proceeds of our participants were used to pay the intangible drilling costs of our wells and a portion of the tangible costs. “Intangible drilling costs” generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. “Tangible costs” generally means
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the equipment costs of drilling and completing a well that are not currently deductible as intangible drilling costs and are not lease costs. Our managing general partner was required to contribute all of the leases on which our wells are situated, pay and/or contribute services towards our organization and offering costs up to an amount equal to 15% of our participants’ subscription proceeds and pay the majority of our equipment costs to drill and complete our wells. As of December 31, 2006, the aggregate amount of these contributions by our managing general partner was $9,751,300.
Our investment objectives are to:
| • | Provide monthly cash distributions from the wells drilled with our subscription proceeds until the wells are depleted, with a minimum annual return of capital of 10% aggregate cash distributions per Unit to our participants, which is equal to at least $2,500 per Unit, regardless of the actual subscription price paid, during the first five years beginning with our first distribution of production revenues to our participants. These distributions during the first five years are not guaranteed, but are subject to our managing general partner’s subordination obligation as described in Item 11 “Description of Registrant’s Securities to be Registered – Distributions and Subordination.” | ||
| Under current conditions, and based in part on the drilling results of our 41.63 net initial wells (18% of our total estimated net wells) which were drilled in 2006, we believe that our participants will receive these minimum aggregate distributions of $2,500 per Unit per year during this five year period. See Item 3 “Properties” and Note 2 of the “Notes to Financial Statements” in Item 13 “Financial Statements and Supplementary Data.” However, we do not yet know the drilling results of all of the approximately 188.13 net wells (82% of our total estimated net wells) which we prepaid in 2006 and are currently in the process of being drilled and completed. Therefore, a participant should not place too much reliance on the results of the initial wells we drilled in 2006, until we have finished all of our drilling activities. Also, current conditions, such as prices for natural gas and our costs for operating our wells, will change during the next five years. See Item 1A “Risk Factors – Risks Relating to Our Business.” | |||
| • | Obtain federal income tax deductions in 2006 from intangible drilling costs in an amount guaranteed to equal not less than 90% of each participant’s subscription price for his or her Units. These deductions for intangible drilling costs may be used to offset a portion of the participant’s taxable income, subject to any objections by the IRS, each participant’s individual tax circumstances, and the passive activity rules if the participant invested in us as a limited partner. For example, if a participant paid $25,000 for a Unit the investment would produce a 2006 tax deduction of not less than $22,500 per unit, 90%, against: |
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| • | ordinary income, or capital gain in some situations, if the participant invested as an investor general partner; and | ||
| • | passive income if the participant invested as a limited partner. |
In the first quarter of 2007, our IRS Schedule K-1’s to our participants reported a deduction for intangible drilling costs in 2006 in an amount equal to 90% of the subscription price paid by each participant. However, we do not guarantee the IRS’ treatment of our participants’ deductions for intangible drilling costs. If the IRS were to decrease the amount of the deduction, or defer part of the deduction to 2007 for wells we prepaid in 2006, for example, our participants would not be entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits.
| • | Offset a portion of any gross production income generated by us with tax deductions from percentage depletion. | ||
| • | Provide each of our participants with tax deductions, in an aggregate amount guaranteed to equal the remaining 10% of the participant’s initial investment in us, through annual depreciation deductions over a seven-year cost recovery period. The tax benefits of these depreciation deductions to our participants are subject to any objections by the IRS, each participant’s individual tax circumstances, and the passive activity rules if the participant invested as a limited partner or is a converted limited partner. Also, we do not guarantee the IRS’ treatment of our participants’ depreciation deductions for our equipment costs. If the IRS were to decrease the amount of the deductions, for example, our participants would not entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits. |
We are filing this General Form for Registration of Securities on Form 10 to register our Units pursuant to Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We are subject to the registration requirements of Section 12(g) because at the end of our first fiscal year on December 31, 2006, the aggregate value of our assets exceeded the applicable threshold of $10 million and our Units of record were held by more than 500 persons. Because of our obligation to register our Units with the Securities and Exchange Commission (the “SEC”) under the Exchange Act, we will be subject to the requirements of the Exchange Act rules. In particular, we will be required to file:
| • | quarterly reports on Form 10-QSB; | ||
| • | annual reports on Form 10-KSB; | ||
| • | current reports on Form 8-K; and |
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| • | otherwise comply with the disclosure obligations of the Exchange Act applicable to issuers filing registration statements pursuant to Section 12(g) of the Exchange Act. |
Oil and Natural Gas Properties.We have drilled 41.63 net development wells and are in the process of completing those wells. In addition, we are drilling and completing approximately 188.13 additional net development wells, the participants’ costs of which were prepaid in 2006, but which were spudded in the first quarter of 2007. Because all of our wells have not yet been drilled and completed, our investor general partner units have not yet been converted to limited partner units. We will not drill any wells except the wells funded with our initial subscription proceeds and our managing general partner’s capital contributions to us as described above. For further information concerning our natural gas and oil properties, including our leasing practices and our reserve and acreage information, see Item 3 “Properties.”
We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 “Financial Information.” Thus, the subscription proceeds from the offering of our Units in 2006 and our ongoing natural gas and oil production revenues from our wells will satisfy all of our cash requirements and we will not seek to raise additional funds from either our participants or new investors. We pay our managing general partner a monthly well supervision fee of $362 per well, as outlined in our drilling and operating agreement, for serving as the operator of our wells. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and to a lesser extent oil, such as:
| • | well tending, routine maintenance and adjustment; | ||
| • | reading meters, recording production, pumping, maintaining appropriate books and records; and | ||
| • | preparing reports to us and to government agencies. |
The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, rebuilding of access roads and brine disposal or third-party services. If these expenses are incurred, we will pay these expenses at the invoice cost for third-party services performed and materials purchased. Also, we will pay a reasonable charge for services performed directly by our managing general partner or its affiliates.
Production.All of our wells are expected to produce, and some of our wells are currently producing, natural gas and to a far lesser extent oil, which are our only products. We do not plan to sell any of our wells and will continue to produce them until they are depleted, at which time they will be plugged and abandoned. See Item 3 “Properties” for information concerning:
| • | our natural gas and oil production quantities; |
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| • | average sales prices; and | ||
| • | average production costs. |
Sale of Natural Gas and Oil Production.Our managing general partner is responsible for selling our natural gas and oil production. In the geographic areas where our wells are situated, our managing general partner is a party to natural gas contracts with various natural gas purchasers, each of which is paying a different price for our natural gas.
Our managing general partner is responsible for gathering and transporting the natural gas produced by us to interstate pipeline systems, local distribution companies, and/or end-users in the area (the “gathering services”). We pay our managing general partner a competitive gathering fee for this service which our managing general partner has determined is currently an amount equal to 13% of the gross sales price received by us for our natural gas. Gross sales price means the price that is actually received by us, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements. Our managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners for the majority of our natural gas production. Our managing general partner’s affiliate, Atlas America, Inc., which is sometimes referred to as “Atlas America,” or another affiliate, controls and manages the gathering system for Atlas Pipeline Partners. Also, Atlas America and our managing general partner’s affiliates, Resource Energy, LLC, sometimes referred to as “Resource Energy,” and Viking Resources LLC, sometimes referred to as “Viking Resources,” which are sometimes referred to collectively as the “Atlas Entities”, which do not include us, have an agreement with Atlas Pipeline Partners under which generally all of the gas produced by their affiliated partnerships, which does include us, will be gathered and transported through the gathering system owned by Atlas Pipeline Partners, and provides that the Atlas Entities must pay the greater of $.35 per mcf or 16% of the gross sales price for each mcf transported by these affiliated partnerships through Atlas Pipeline Partners’ gathering system. Subject to the agreement with Atlas Pipeline Partners described above, in providing the gathering services our managing general partner may use gathering systems owned by Atlas Pipeline Partners, independent third-parties and/or affiliates of Atlas America other than Atlas Pipeline Partners.
The payment of a competitive gathering fee to our managing general partner for its gathering services is subject to the following conditions:
| • | If we use the gathering system owned by Atlas Pipeline Partners, then our managing general partner will apply the gathering fee it receives from us towards the payments owed by the Atlas Entities under their agreement with Atlas Pipeline Partners. | ||
| • | If we use a third-party gathering system, our managing general partner will pay a portion or all of the gathering fee it receives from us to the third-party gathering the natural gas. Our |
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| managing general partner may retain the excess of any gathering fees it receives from the partnership over the payments it makes to third-party gas gatherers. If the third-party’s gathering system charges more than an amount equal to 13% of the gross sales price, then our managing general partner’s gathering fee charged to us will be the actual transportation and compression fees charged by the third-party gathering system with respect to our natural gas in the area. | |||
| • | If we use both a third-party gathering system and the Atlas Pipeline Partners gathering system (or a gas gathering system owned by an affiliate of Atlas America other than Atlas Pipeline Partners), then our managing general partner will receive an amount equal to 13% of the gross sales price plus the amount charged by the third-party gathering system. For purposes of illustration, but not limitation, certain wells drilled by us in the Upper Devonian Sandstone Reservoirs in the McKean County, Pennsylvania secondary area will deliver natural gas produced in this area into a gathering system, a segment of which will be provided by Atlas Pipeline Partners and a segment of which will be provided by a third-party. In this area, our managing general partner’s competitive gathering fee will include the third-party’s fee of $.35 per mcf for transportation and compression, including any increase in the fee by the third-party gatherer from time-to-time, which it will then pay to the third-party gatherer, and our managing general partner will also receive a gathering fee equal to 13% of the gross sales price. |
Finally, in connection with the Knox project in the Mississippian and Devonian Shale Reservoirs in the Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee area, we will deliver natural gas into a gathering system provided by Knox Energy, which is referred to as the Coalfield Pipeline. The Coalfield Pipeline will receive gathering fees of $.55 per mcf plus fees for compression, which it may increase from time-to-time. If the Coalfield Pipeline does not have sufficient capacity to compress and transport the natural gas produced from our wells as determined by Atlas America, then Atlas America or an affiliate other than Atlas Pipeline Partners may construct an additional gathering system and/or enhancements to the Coalfield Pipeline. On completion of the construction, Atlas America will transfer its ownership in the additional gathering system and/or enhancements to the owners of the Coalfield Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of natural gas transported through the newly constructed and/or enhanced gathering system. If the events described above occur, Coalfield Pipeline will pay this amount to Atlas America from the gathering and compression fees it charges to us. Our managing general partner’s gathering fee in this area also will be 13% of the gross sales price of our natural gas, but will be increased to include the amount of the Coalfield Pipeline fees, if greater, which our managing general partner will then pay to the Coalfield Pipeline.
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See Item 5 “Directors and Executive Officers – Organizational Diagram and Security Ownership of Beneficial Owners.”
We have three primary areas where we are drilling our wells. Our managing general partner anticipates that more prospects will be drilled in the Fayette County area, which is one of the primary drilling areas, than in the other areas, and the natural gas produced from the Fayette County area will be sold to UGI Energy Services, ConocoPhillips Company, Equitable Gas Corporation and Colonial Energy pursuant to contracts which end March 31, 2008, except with respect to Colonial Energy which ends March 31, 2009. The natural gas produced from north central Tennessee, which is one of the three primary areas, will be sold to Knox Energy, LLC pursuant to a contract which ends October 31, 2008. After this contract ends, it is anticipated that Atlas America will market its production in the future to purchasers which are not currently known. Before April, 2007, any natural gas produced from our wells drilled in the other primary area (Crawford County area of the Clinton/Medina geological formation in western Pennsylvania) and the secondary areas, other than Armstrong and McKean Counties, Pennsylvania, was sold to Hess Corporation (“Hess”), as discussed below. After April 1, 2007, our managing general partner anticipates that natural gas produced from the Crawford County area of the Clinton/Medina geological formation in western Pennsylvania, which is a primary area, and the Upper Devonian Sandstone Reservoirs in Armstrong and McKean County, Pennsylvania, which are secondary areas, will be sold to Intrastate Gas Supply, Inc. pursuant to a contract which ends December 31, 2008. Further, all of the natural gas contracts, including those described above, are between the natural gas purchaser and Atlas America, Atlas Energy Resources, LLC and/or their affiliates. Either Atlas America, Atlas Energy Resources, LLC or their affiliates will receive sales proceeds from the natural gas purchasers and then distribute the sales proceeds to us based on the volume of natural gas produced by us. Until the sales proceeds are distributed to us, they will be subject to the claims of Atlas America’s, Atlas Energy Resources, LLC’s or their affiliates’ creditors.
Our managing general partner and its affiliates previously entered into a 10-year agreement with First Energy Solutions Corporation, which was sold by First Energy Solutions Corporation to Hess effective April 1, 2005. Subject to the exceptions set forth below, Hess has the right to buy all of the natural gas produced and delivered by our managing general partner and its affiliates, which includes us, at certain delivery points with the facilities of East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and National Fuel Gas Supply, Columbia Gas Transmission Corporation and Tennessee Gas Pipeline Company, which are interstate pipelines. This contract, which ends April 1, 2009, is important to our managing general partner and its affiliates because as of July 31, 2006 our managing general partner and its affiliates, including its prior affiliated partnerships, were selling approximately 40.9% of their natural gas production under the agreement with Hess. However, as set forth above, we will sell a much smaller percentage of our natural gas to Hess because of certain exceptions to the agreement, including natural gas sold through interconnects established after the agreement, which includes the
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majority of the natural gas produced from wells in the Fayette County, Pennsylvania area and natural gas produced from well(s) subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas such as natural gas produced from wells in north central Tennessee, one of the primary drilling areas, or in Armstrong and McKean Counties, Pennsylvania, which are both secondary drilling areas, as discussed above.
The pricing and delivery arrangements with all of the natural gas purchasers described above are tied to the settlement of the New York Mercantile Exchange Commission (“NYMEX”) monthly futures contracts price, which is reported daily in the Wall Street Journal and with an additional premium, which is referred to as the basis, paid because of the location of the natural gas (the Appalachian Basin) in relation to the natural gas market. The premium over quoted prices on the NYMEX received by our managing general partner and its affiliates has ranged between $0.51 to $1.07 per mcf during our managing general partner’s past three fiscal years. These figures are based on the overall weighted average that our managing general partner and its affiliates used in their annual reserve reports for their past three fiscal years. Generally, the purchase agreements may be suspended for force majeure, which generally means an Act of God.
Pricing for natural gas and oil has been volatile and uncertain for many years. To limit our managing general partner’s and its partnerships’ (including us) exposure to decreases in natural gas prices, our managing general partner and its affiliates, Atlas America and/or Atlas Energy Resources, LLC, use physical hedges through their natural gas purchasers, as discussed below, and financial hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The physical hedges require firm delivery of natural gas and, therefore, are considered normal sales of natural gas, rather than hedges, for accounting purposes. The futures contracts employed by our managing general partner are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, our managing general partner has established a committee to assure that all financial trading is done in compliance with our managing general partner’s hedging policies and procedures. Our managing general partner does not intend to contract for positions that it cannot offset with actual production.
All of the natural gas purchasers described above and many third-party marketers use NYMEX based financial instruments to hedge their pricing exposure, and they make price hedging opportunities available to our managing general partner. The physical hedges are similar to NYMEX based futures contracts, swaps and options, but also require firm physical delivery of the natural gas. Because of this, our managing general partner limits these arrangements to much smaller quantities of natural gas than those projected to be available at any delivery point. The price paid by the natural gas purchasers for certain volumes of natural gas sold under these physical hedge agreements may be significantly different from the underlying monthly spot market
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value. As of April 2, 2006, a portion of our managing general partner’s natural gas was subject to physical hedges through March 31, 2007. After March 31, 2007, none of our managing general partner’s and its affiliates’ natural gas, including our natural gas, is subject to physical hedges and our managing general partner and its affiliates anticipate using financial hedges as discussed below for all of the natural gas that is hedged, although this may change from time to time.
Atlas America implements financial hedges through its banking counter-parties, Wachovia Bank, and KeyBank. Atlas America on behalf of the partnerships, including us, expects to hedge approximately a significant amount of the natural gas production using fixed-for-floating financial swaps. In this regard, the partnerships, including us, have confirmed their authorization to Atlas America and/or Atlas Energy Resources, LLC to enter into the hedging agreements, and have ratified all actions previously taken by Atlas America and/or Atlas Energy Resources, LLC in connection therewith. It is anticipated that since the transfer by Atlas America of our managing general partner to Atlas Energy Resources, LLC, as discussed in Item 5 “Directors and Executive Officers,” a subsidiary of Atlas Energy Resources, LLC, rather than Atlas America, will enter into these hedging arrangements.
The percentages of natural gas that are hedged through either financial hedges, physical hedges or not hedged at all will change from time to time in the discretion of Atlas America or Atlas Energy Resources, LLC. It is difficult to project what portion of these hedges will be allocated to us by our managing general partner and its affiliates because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by us. Although hedging provides us some protection against falling prices, these activities also could reduce the potential benefits of price increases and we could incur liability on the financial hedges. For example, if our production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts or there is a sudden, unexpected event materially impacting natural gas prices, then we would be exposed to the risk of a financial loss. Subject to our managing general partner’s and its affiliates’ interest in their natural gas contracts or pipelines and gathering systems, all benefits and liabilities from marketing and hedging or other relationships affecting the property of our managing general partner or its affiliates or us must be fairly and equitably apportioned according to the interests of each in the property. In this regard, the benefits and liabilities of the hedging agreements will be equitably allocated by Atlas America and/or Atlas Energy Resources, LLC and our managing general partner to us and the other partnerships sponsored by our managing general partner and its affiliates pro rata based on actual production, consistent with past practice, and we and the other partnerships sponsored by our managing general partner and its affiliates will be severally liable for our respective allocated share of the liabilities under the hedging agreements, but will not be jointly and severally liable for the entire amount of the liabilities under the hedging agreements. Additionally, Atlas America and/or Atlas Energy Resources, LLC will not be liable for any of
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those liabilities, or be entitled to any of those benefits, to the extent they are allocated to us and the other partnerships sponsored by our managing general partner and its affiliates.
Crude oil produced from our wells will flow directly into storage tanks where it will be picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. Our managing general partner anticipates selling any oil produced by our wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales.
Major Customers.Our natural gas and oil is sold under contract to various purchasers. For the period ended December 31, 2006, sales to UGI Energy Services, Inc., Dominion Field Services, Inc. and Colonial Energy, Inc. accounted for 61%, 22% and 17%, respectively, of total revenues. No other customer accounted for more than 10% of our total revenues for the period ended December 31, 2006. As of December 31, 2006, however, only six of the total 229.76 net wells we expect to drill and complete were online and producing natural gas. Thus, our percentages of sales to the customers set forth above should not be considered representative of our sales and customers after all of our wells are online and producing.
Competition.The energy industry is intensely competitive in all of its aspects. Competition arises not only from numerous domestic and foreign sources of natural gas and oil, but also from other industries that supply alternative sources of energy. In selling our natural gas and oil, product availability and price are our principal means of competition. We may also encounter competition in obtaining drilling and operating services from third-party providers. Any competition we encounter could delay the drilling and/or operating of our wells, and thus delay the distribution of our revenues to our participants. While it is impossible for us to accurately determine our comparative position in the natural gas and oil industry, we do not consider our operations to be a significant factor in the industry.
Markets.The availability of a ready market for natural gas and oil, and the price obtained, depend on numerous factors beyond our control as described below in Item 1A “Risk Factors – Risks Relating to Our Business.” During fiscals 2006, 2005, and 2004 our managing general partner did not experience problems in selling its and its affiliates’ natural gas and oil, although prices varied significantly during and after those periods.
Governmental Regulation
Regulation of Production.The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the number of wells, or the locations where we can drill wells, although we can apply for exemptions to the regulations to reduce the
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well spacing. Also, each state generally imposes a production or severance tax for the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation and Sale of Natural Gas.Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission (“FERC”) regulates the interstate transportation of natural gas.
Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to the supply and demand for natural gas along with factors such as the natural gas’ BTU content and where the wells are located. Since 1985 FERC has sought to promote greater competition in natural gas markets in the United States. Traditionally, natural gas was sold by producers to interstate pipeline companies that served as wholesalers and resold the natural gas to local distribution companies for resale to end-users. FERC changed this market structure by requiring interstate pipeline companies to transport natural gas for third-parties. In 1992 FERC issued Order 636 and a series of related orders that required pipeline companies to, among other things, separate their sales services from their transportation services and provide an open access transportation service that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas producers or suppliers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over another natural gas seller because it also provides transportation services.
In 2000 FERC issued Order 637 and subsequent orders to enhance competition by removing price ceilings on short-term capacity release transactions. It also enacted other regulatory policies that are intended to enhance competition in the natural gas market and increase the flexibility of interstate natural gas transportation. FERC has further required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices.
Crude Oil Regulation.Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials.
State Regulation.Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources and our oil and gas operations in Tennessee are regulated by the Tennessee Department of Environment and Conservation. Pennsylvania, Tennessee and the other states where our wells may be situated impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including
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supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, the regulations involve:
| • | new well permit and well registration requirements, procedures, and fees; | ||
| • | landowner notification requirements; | ||
| • | certain bonding or other security measures; | ||
| • | minimum well spacing requirements; | ||
| • | restrictions on well locations and underground gas storage; | ||
| • | certain well site restoration, groundwater protection, and safety measures; | ||
| • | discharge permits for drilling operations; | ||
| • | various reporting requirements; and | ||
| • | well plugging standards and procedures. |
Environmental Regulation.Our drilling and producing operations are subject to various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment. The Environmental Protection Agency and state and local agencies will require us to obtain permits and take other measures with respect to:
| • | the discharge of pollutants into navigable waters; | ||
| • | disposal of wastewater; and | ||
| • | air pollutant emissions. |
If these requirements or permits are violated, there can be substantial civil and criminal penalties which will increase if there was willful negligence or misconduct. In addition, we may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by our drilling activities or the well and its production.
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Additionally, the well owners’ or operators’ liability can extend to pollution costs from situations that occurred before their acquisition of the well. Pennsylvania and Tennessee have either adopted federal standards or promulgated their own environmental 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. Although compliance may cause delays in drilling our wells, which we do not anticipate, or increase our costs, currently we do not believe these costs will be substantial. However, we cannot predict the ultimate costs of complying with present and future environmental laws and regulations because these laws and regulations are constantly being revised, and ultimately they may have a material impact on our operations or costs to remain in compliance. Additionally, we cannot obtain insurance to protect against many types of environmental claims, including remediation costs.
Dismantlement, Restoration, Reclamation and Abandonment Costs.When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to which we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreement, our managing general partner and our participants are allocated abandonment costs in the same ratio in which they share in our production revenues (currently 32.6% to our managing general partner and 67.4% to our participants) and the salvage proceeds are allocated between our managing general partner and our participants in the same ratio in which they were charged with our equipment costs, which we estimate will charged be 70% to our managing general partner and 30% to our participants.
As a consequence of the allocation provisions of the partnership agreement described above, our managing general partner generally will receive proceeds from salvaged equipment at least equal to, and typically exceeding, its share of the related equipment costs, whereas our participants may have a shortfall. To cover our participants’ potential shortfall, beginning one year after each of our wells has been placed into production our managing general partner, serving as operator, may retain $200 of our revenues per month to cover the estimated future plugging and abandonment costs of the well. See Notes to Financial Statements.
Employees.We have no employees. Instead, we rely on our managing general partner for management services, and our managing general partner relies on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for certain management and administrative services and financing for capital expenditures. See Item 5 “Directors and Executive Officers.”
ITEM 1A. RISK FACTORS
Statements made by us that are not strictly historical facts are “forward-looking” statements that are based on current expectations about our business and assumptions made by our managing general partner. These
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statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than those predicted. The following section entitled “Risks Relating to Our Business” includes some, but not all, of those factors or uncertainties.
Risks Relating to Our Business
Natural Gas and Oil Prices are Volatile and a Substantial Decrease in Prices, Particularly Natural Gas Prices, Would Decrease Our Revenues, Our Cash Distributions and the Value of Our Properties and Could Reduce Our Managing General Partner’s Ability to Loan Us Funds and Meet Its Ongoing Obligations to Indemnify Our Investor General Partners and Purchase Units Under Our Presentment Feature.A substantial decrease in natural gas and oil prices, particularly natural gas prices, would decrease our revenues and the value of our natural gas and oil properties. Our future financial condition and results of operations, and the value of our natural gas and oil properties, will depend on market prices for natural gas and, to a much lesser extent, oil. Further, if natural gas and oil prices decrease during the first years of production from our wells, which is when the wells typically achieve their greatest level of production, there would be a greater adverse effect on our distributions to our participants than price decreases in later years when the wells have a lower level of production. Also, our participants’ return level will decrease during our term, even if there are rising natural gas prices, because of reduced production volumes from our wells.
Natural gas and oil prices historically have been volatile and will likely continue to be volatile in the future. Prices our managing general partner has received during its past three fiscal years for its natural gas have ranged from a high of $10.24 per mcf in the quarter ended December 31, 2005 to a low of $6.00 per mcf in the quarter ended March 31, 2004.
Prices for natural gas and oil are dictated by supply and demand factors and prices may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, and market uncertainty. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices. Other factors affecting the price and/or marketing of natural gas and oil production, which are beyond our control and cannot be accurately predicted, are the following:
| • | the cost, proximity, availability, and capacity of pipelines and other transportation facilities; | ||
| • | the price and availability of other energy sources such as coal, nuclear energy, solar and wind; | ||
| • | the price and availability of alternative fuels, including when large consumers of natural gas are able to convert to alternative fuel use systems; | ||
| • | local, state, and federal regulations regarding production, conservation, and transportation; | ||
| • | overall domestic and global economic conditions; |
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| • | the impact of the U.S. dollar exchange rates on natural gas and oil prices; | ||
| • | technological advances affecting energy consumption; | ||
| • | domestic and foreign governmental relations, regulations and taxation; | ||
| • | the impact of energy conservation efforts; | ||
| • | the general level of supply and market demand for natural gas and oil on a regional, national and worldwide basis; | ||
| • | weather conditions and fluctuating seasonal supply and demand for natural gas and oil because of various factors such as home heating requirements in the winter months, although seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation, and certain natural gas users with natural gas storage facilities purchase a portion of the natural gas they anticipate they will need for the winter during the summer, which also can lessen seasonal demand fluctuations; | ||
| • | economic and political instability, including war or terrorist acts in natural gas and oil producing countries, including those of the Middle East and South America; | ||
| • | the amount of domestic production of natural gas and oil; and | ||
| • | the amount and price of imports of natural gas and oil from foreign sources, including liquid natural gas from Canada and other countries (which our managing general partner believes becomes economic when natural gas prices are at or above $3.50 per mcf), and the actions of the members of the Organization of Petroleum Exporting Countries (“OPEC”), which include production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels. |
These factors make it extremely difficult to predict natural gas and oil price movements with any certainty.
For example, the North American Free Trade Agreement (“NAFTA”) eliminated trade and investment barriers in the United States, Canada, and Mexico. From time to time since then there have been increased imports of Canadian natural gas into the United States. Without a corresponding increase in demand in the United States, the imported natural gas would have an adverse effect on both the price and volume of natural gas sales from our wells.
Price decreases would reduce the amount of our cash flow available for distribution to our participants and could make some of our reserves uneconomic to produce which would reduce our reserves and cash flow. Additionally,
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price decreases may cause the lenders under our managing general partner’s credit facility to reduce its borrowing base because of lower revenues or reserve values, which would reduce our managing general partner’s liquidity, and, possibly, require mandatory loan repayments from our managing general partner. This would reduce our managing general partner’s ability to loan us money or to meet its ongoing partnership obligations, such as indemnification of our investor general partners for liabilities in excess of their pro rata share of our assets and insurance proceeds and purchasing units presented by our participants, although this presentment right may be suspended by our managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange for financing or other consideration for this purpose on reasonable terms.
Further, natural gas and oil prices do not necessarily move in tandem. Because the majority of our proved reserves are currently natural gas reserves, we are more susceptible to movements in natural gas prices. Also, even though hedging provides us some protection against falling natural gas prices, it also could reduce the potential benefits of price increases if the spot market natural gas price is higher than the price paid under those arrangements at the time the natural gas is to be delivered. With respect to the financial hedging of production, if the production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts natural gas prices, we may be exposed to the risk of financial loss.
Drilling Wells is Highly Speculative and We Could Drill Some Wells That Are Nonproductive or That Are Productive, But Fail to Return the Costs of Drilling and Operating Them, and the Drilling of Some of Our Wells Could Be Curtailed, Delayed or Cancelled If Unexpected Events Occur.The amount of recoverable natural gas and oil reserves may vary significantly from well to well. We may drill some wells that are nonproductive (i.e. “dry holes”), or wells that are profitable on an operating basis, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs are taken into account. The geologic data and technologies available do not allow us to know conclusively before drilling a well whether or not natural gas or oil is present or can be produced economically.
The cost of drilling, completing and operating a well is often uncertain. For example, the increase in natural gas and oil prices over the last several years has increased the demand for drilling rigs and other related equipment, and the costs of drilling and completing natural gas and oil wells also have increased. This has increased our well costs since our wells are drilled by our managing general partner, serving as our general drilling contractor, at cost plus a nonaccountable fixed payment reimbursement to our managing general partner for our participants’ share of our managing general partner’s administrative and oversight fee of $15,000 per well, plus 15% of the cost and the nonaccountable fee fixed payment reimbursement.
Further, some of our drilling operations may be curtailed, delayed or cancelled as a result of many factors, including:
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| • | title problems; | ||
| • | environmental or other regulatory concerns; | ||
| • | costs of, or shortages or delays in the availability of, oil field services and equipment; | ||
| • | unexpected drilling conditions; | ||
| • | unexpected geological conditions; | ||
| • | adverse weather conditions; and | ||
| • | equipment failures or accidents. |
Any one or more of the factors discussed above could reduce or delay our receipt of natural gas and oil production revenues, thereby reducing or delaying distributions to our participants. As discussed in Item 3 “Properties,” most of our wells are not yet completed and online.
Our Managing General Partner’s Management Obligations to Us Are Not Exclusive, and if It Does Not Devote the Necessary Time to Our Management There Could Be Delays in Providing Timely Reports and Distributions to Our Participants, and Our Managing General Partner, Serving as Operator of Our Wells, May Not Supervise the Wells Closely Enough. We do not have any officers, directors or employees. Instead, we rely totally on our managing general partner and its affiliates for our management. Our managing general partner is required to devote to us the time and attention that it considers necessary for the proper management of our activities. However, our managing general partner and its affiliates currently are, and will continue to be, engaged in other natural gas and oil activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during our term. This creates a continuing conflict of interest in allocating management time, services, and other activities among us and its other activities. If our managing general partner does not devote the necessary time to our management, there could be delays in providing timely annual and semi-annual reports, tax information and cash distributions to our participants. Also, if our managing general partner, serving as the operator of our wells, does not supervise the wells closely enough, for example, there could be delays in undertaking remedial operations on a well, if necessary, to increase the production of natural gas and/or oil from the well. However, our managing general partner intends to allocate its management time, services and other functions on an as-needed basis consistent with its fiduciary duties among us and its other activities so that our administration as a partnership and our natural gas and oil operations are managed properly.
Current Conditions May Change and Reduce Our Proved Reserves, Which Could Reduce Our Revenues.A participant will be able to recover his investment in us only through our distribution of our net sales proceeds from the production of natural gas and oil from our productive wells. The quantity of natural gas and oil in a
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well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. Our proved reserves will decline as they are produced from our wells, and once all of our wells are online our distributions to our participants generally will decrease each year until our wells are depleted.
Our proved reserves at December 31, 2006 from the six net wells that we drilled, completed and placed online for production in 2006 of the total 229.76 net wells we anticipate are set forth in Item 3 “Properties – Natural Gas and Oil Reserve Information.” Under current conditions, our managing general partner is reasonably certain that those proved reserves will be produced over the life of our wells. However, there is an element of uncertainty in all estimates of proved reserves, and current conditions, such as natural gas and oil prices and the costs of operating our wells and transporting our natural gas, could change in the future and could reduce the amount of our current proved reserves. Since estimated proved reserves from only six net wells are presented in Item 3 “Properties – Natural Gas and Oil Reserve Information,” our revenues from the sale of our natural gas and oil production once all of our wells have been drilled and placed online for production may vary significantly from our expectations associated with the current estimated proved reserves of the six wells we drilled and placed online for production in 2006. Also, we base our estimates of our proved natural gas and oil reserves and future net revenues from those reserves on analyses that rely on various assumptions, including those required by the SEC, as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in the future in these assumptions, and, in our case, assumptions concerning future natural gas prices, could materially affect the estimated quantity of our reserves. Actual production, natural gas and oil prices, taxes, development expenses, operating expenses, availability of funds, and quantities of recoverable natural gas and oil reserves in the future will vary substantially from our estimates or the estimates contained in the reserve reports referred to in Item 3 “Properties,” as discussed above.
Our properties also may be susceptible to hydrocarbon drainage from production on adjacent properties in which we do not have an interest. In addition, our proved reserves may be revised downward in the future based on the following:
| • | the actual production history of our wells; | ||
| • | results of future exploration and development in the area; | ||
| • | decreases in natural gas and oil prices; | ||
| • | governmental regulation; and | ||
| • | other changes in current conditions, many of which are beyond our control. |
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Government Regulation of the Oil and Natural Gas Industry is Stringent and Could Cause Us to Incur Substantial Unanticipated Costs for Regulatory Compliance, Environmental Remediation of Our Well Sites (Which May Not Be Fully Insured) and Penalties, and Could Delay or Limit Our Drilling Operations.We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration, development, production and sales of natural gas and oil are subject to extensive federal, state and local regulations. We discuss our regulatory environment in more detail in Item 1 “Business – Governmental Regulation.” We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Other regulations may limit our operations. For example, “frost laws” prohibit drilling rigs and other heavy equipment from using certain roads during winter. This is important to us, because in 2006 we prepaid the costs of most of our wells, including the currently deductible intangible drilling costs of the wells, and the drilling of each of those prepaid wells was to begin on or before March 31, 2007 under our drilling and operating agreement. Although the drilling of all of our prepaid wells did begin on or before March 31, 2007, government regulations such as the “frost laws” could delay the completion of our prepaid wells. Also, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income.
In addition, our operations may cause us to incur substantial liabilities to comply with environmental laws and regulations. Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:
| • | require the acquisition of a permit before drilling begins; | ||
| • | restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities; | ||
| • | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and | ||
| • | impose substantial liabilities for pollution resulting from our operations. |
Failure to comply with these laws and regulations may result in the following:
| • | assessment of administrative, civil, and criminal penalties; | ||
| • | incurrence of investigatory or remedial obligations; or | ||
| • | imposition of injunctive relief. |
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Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transporting, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance or could restrict our methods or times of operation. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. We discuss the environmental laws that affect our operations in more detail under Item 1 “Business – Governmental Regulation – Environmental Regulation.”
Pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could reduce our revenues and the value of our assets.
Our Natural Gas and Oil Activities Are Subject to Drilling and Operating Hazards Which Could Result in Substantial Losses to Us. Well blowouts, cratering, explosions, uncontrollable flows of natural gas, oil or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks are inherent drilling and operating hazards for us. The occurrence of any of those hazards could result in substantial losses to us, including liabilities to third-parties or governmental entities for damages resulting from the occurrence of any of those hazards and substantial investigation, litigation and remediation costs.
Our Total Annual Cash Distributions During Our First Five Years May be Less Than $2,500 Per Unit. If our participants’ cash distributions from us are less than a 10% return of their capital (which is $2,500 per Unit based on a $25,000 Unit regardless of the actual price paid) for each of the first five 12-month periods beginning with our first cash distributions from operations, then our managing general partner has agreed to subordinate a portion of its share of our net production revenues. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination our participants may not receive the 10% return of capital for each of the first five years as described above. Also, at any time during the subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent our participants’ cash distributions from us exceed the 10% return of capital described above. A more detailed discussion of our managing general partner’s subordination obligation is set forth in Item 11 “Description of Registrant’s Securities to be Registered – Distributions and Subordination.” Also see “– Current Conditions May Change and Reduce Our Proved Reserves, Which Could Reduce Our Revenues,” above.
Increases in Drilling and Operating Costs Could Decrease Our Net Revenues from Our Wells.The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services, such as increased costs for tubular steel, have increased our drilling, completing and operating costs to some degree as
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compared to those well costs in our managing general partner’s prior partnerships, and could decrease our net revenues from our wells. Although shortages of drilling rigs, equipment, supplies or personnel have not delayed the drilling of our wells, such shortages could delay completing some of our wells or connecting them to gathering lines, which would delay our receipt of production revenues from the wells.
Our Limited Operating History Creates Greater Uncertainty Regarding Our Ability to Operate Profitably.Our limited history of operating our wells may not indicate the results that we may achieve in the future. Our success depends on generating sufficient revenues by producing sufficient quantities of natural gas and oil from our wells and then marketing that natural gas and oil at sufficient prices to pay the operating costs of our wells and our administrative costs of conducting business as a partnership, and still provide a reasonable rate of return on our participants’ investment in us. If we are unable to pay our costs, then we may need to:
| • | borrow funds from our managing general partner, which is not contractually obligated to make any loans to us; | ||
| • | shut-in or curtail production from some of our wells; or | ||
| • | attempt to sell some of our wells, which we may not be able to do on terms that are acceptable to us. |
Also, the events set forth below could decrease our revenues from our wells and/or increase our expenses of operating our wells:
| • | decreases in the price of natural gas and oil, which are volatile; | ||
| • | changes in the oil and gas industry, including changes in environmental regulations, which could increase our costs of operating our wells in compliance with any new environmental regulations; | ||
| • | an increase in third-party costs for equipment or services, or an increase in gathering and compression fees for transporting our natural gas production; and | ||
| • | problems with one or more of our wells, which could require repairing or performing other remedial work on a well or providing additional equipment for the well. |
Competition May Reduce Our Revenues from the Sale of Our Natural Gas. Competition from other natural gas producers and marketers in the Appalachian Basin, as well as competition from alternative energy sources, may make it more difficult to market our natural gas. Our competitors may be able to offer their natural gas to natural gas purchasers on better terms, such as lower prices or a greater volume of natural gas that can be delivered to the purchaser, which we cannot match. Also, other energy sources such as coal may be available to
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the purchasers at a lower price. As a result, we may have to seek other natural gas purchasers and we may receive lower prices for our natural gas and incur higher transportation and compression fees if we sell our natural gas to these other natural gas purchasers. In this event, our revenues from the sale of our natural gas would be reduced.
We Sell Our Natural Gas to a Limited Number of Purchasers Without Guaranteed Prices, and if the Prices Paid by the Purchasers Decrease, Our Revenues Also Will Decrease, and if a Purchaser Stops Buying Some or All of Our Natural Gas, the Sale of Our Natural Gas Could Be Delayed Until We Find Another Purchaser and the Substitute Purchaser We Find May Pay a Lower Price, Which Would Reduce Our Revenues. We will depend initially on a limited number of natural gas purchasers to purchase the majority of our natural gas production as described in Item 1 “Business – General – Sale of Natural Gas and Oil Production” and “– General – Major Customers,” and we will not be guaranteed a specific natural gas price, other than through hedging. Thus, if our current purchasers, including those listed above, were to pay a lower price for our natural gas in the future, our revenues would decrease. Also, if our current purchasers, including those listed above, began buying a reduced percentage of our natural gas, or stopped buying any of our natural gas, the sale of our natural gas could be delayed until we found another purchaser, and the substitute purchaser or purchasers we found may pay lower prices for our natural gas, which would reduce our revenues. However, our managing general partner has not experienced any problems with selling natural gas in the past three fiscal years as discussed in Item 1 “Business – General – Markets.”
Also, our managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners for the majority of our natural gas as described in Item 1 “Business – General – Sale of Natural Gas and Oil Production.” Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P., an affiliate of Atlas America, and is the indirect parent company of our managing general partner, controls and manages the gathering system for Atlas Pipeline Partners. (See Item 5 “Directors and Executive Officers – Organizational Diagram and Security Ownership of Beneficial Owners.”) Atlas Pipeline Holdings, L.P., as a public company, may be more susceptible to a change of control from Atlas America’s affiliates to independent third-parties. Also, if Atlas Pipeline Partners GP, LLC were removed as general partner of Atlas Pipeline Partners without cause and without its consent the amount of gathering fees required to be paid by us for natural gas transported through Atlas Pipeline Partners’ gathering system could increase, because Atlas Pipeline Partners GP, LLC would no longer receive revenues from Atlas Pipeline Partners. However, Atlas America and its affiliates would still be obligated to pay the difference between the amount in the master natural gas gathering agreement and the amount paid by us, except with respect to new wells drilled after the removal of the general partner, although we do not anticipate that we would still be drilling new wells at that time. Thus, if that situation ever
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occurred, our managing general partner and its affiliates may have an incentive to increase the gathering fees we pay, which would reduce our cash distributions.
We Could Incur Delays in Receiving Payment, or Substantial Losses if Payment is Not Made, for Natural Gas We Previously Delivered to a Purchaser, Which Could Delay or Reduce Our Revenues and Cash Distributions. There is a credit risk associated with a natural gas purchaser’s ability to pay. We may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In this event, our revenues and cash distributions to our participants also would be delayed or reduced. In accordance with industry practice, we typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before we receive payment. Thus, it is possible that we may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of our natural gas. This credit risk may also reduce the price benefit derived by us from our managing general partner’s natural gas physical hedges, although after March 31, 2007 as described in Item 1 “Business – General – Sale of Natural Gas and Oil Production,” our managing general partner does not have any natural gas subject to physical hedges.
If Third-Parties Participating in Drilling Some of Our Wells Fail to Pay Their Share of the Well Costs, We Would Have to Pay Those Costs in Order to Get the Wells Drilled, and If We Are Not Reimbursed the Increased Costs Would Reduce Our Cash Flow and Possibly Could Reduce the Number of Wells We Can Drill.Third-parties have participated with us in drilling some of our wells. Financial risks exist when the cost of drilling, equipping, completing, and operating wells is shared by more than one person. If we pay our share of the costs, but the other interest owner does not pay its share of the costs, then we would have to pay the costs of the defaulting party. In this event, we would receive the defaulting party’s revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, be sufficient to cover the additional costs we paid. If not, then the increased costs would reduce our cash flow and the number of wells we can drill unless we borrow funds to cover the additional costs or the costs of drilling our other wells is less than expected and those excess funds are used to pay the additional costs that should have been paid by the third-party. However, the third-parties participating in some of our wells currently have not defaulted on any of their respective obligations for those wells.
We Expect to Incur Costs in Connection with Exchange Act Compliance and We May Become Subject to Liability for Any Failure to Comply, Which Will Reduce Our Cash Available for Distribution.As a result of our obligation to register our securities with the SEC under the Exchange Act, we will be subject to Exchange Act Rules and related reporting requirements. This compliance with the reporting requirements of the Exchange Act will require timely filing of quarterly reports on Form 10-QSB, annual reports on Form 10-KSB and current reports on Form 8-K, among other actions. Further, recently enacted and proposed laws, regulations and standards relating to corporate governance and disclosure requirements applicable to public companies, including
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the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and new SEC regulations, have increased the costs of corporate governance, reporting and disclosure practices which are now required of us. In addition, these laws, rules and regulations create new legal grounds for administrative enforcement and civil and criminal proceedings against us in case of non-compliance, which increases our risks of liability and potential sanctions. All of the additional compliance costs described above will decrease the amount of cash available to us to distribute to our participants.
We Intend to Produce Natural Gas and/or Oil from Our Wells Until They Are Depleted, Regardless of Any Changes in Current Conditions, Which Could Result in Lower Returns to Our Participants as Compared With Other Types of Investments Which Can Adapt to Future Changes Affecting Their Portfolios.Our natural gas and oil properties are relatively illiquid because there is no public market for working interests in natural gas and oil wells. In addition, one of our investment objectives is to continue to produce natural gas and oil from our wells until the wells are depleted. Thus, unlike mutual funds, for example, which can vary their portfolios in response to changes in future conditions, we do not intend, and in all likelihood we would be unable, to vary our portfolio of wells in response to future changes in economic and other conditions such as decreases or increases in natural gas or oil prices, or increased operating costs of our wells.
Since Our Managing General Partner Is Not Contractually Obligated to Loan Funds to Us, We Could Have to Curtail Operations or Sell Properties if We Need Additional Funds and Our Managing General Partner Does Not Make the Loan. We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 “Financial Information.” However, a shortfall in funds to pay for our ongoing expenses may arise, for example, for costs associated with repairing or performing other remedial work on a well. If this were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, which are not contractually committed to make a loan. The amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings will be obtained from third-parties. If, for any reason, our managing general partner did not loan us the funds needed for repairing or performing other remedial work on a well, then we might have to curtail our operations on the well or wells which needed the remedial work or we may attempt to sell one or more of our wells, although we may not be able to do so on terms that are acceptable to us.
ITEM 2. FINANCIAL INFORMATION.
Selected Financial Data.The following table sets forth selected financial data for the period ended December 31, 2006, that we derived from our financial statements, which were audited by Grant Thornton LLP, independent registered public accountants, and are included in this Form 10.
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| For the period July 21, 2006 | ||||
| (date of formation) | ||||
| through December 31, 2006 | ||||
Income statement data: | ||||
| Revenues: | ||||
| Gas and oil production | $ | 17,500 | ||
| Total revenues | $ | 17,500 | ||
| Costs and expenses: | ||||
| Gas and oil production | $ | 300 | ||
| Transmission | 1,800 | |||
| General and administration | 12,100 | |||
| Depletion | 4,000 | |||
| Total costs and expenses | $ | 18,200 | ||
| Net loss | (700 | ) | ||
| Basic and diluted net loss per limited partnership unit | $ | (1 | ) | |
| For the period July 21, 2006 | ||||
| (date of formation) | ||||
| through December 31, 2006 | ||||
| Operating data: | ||||
| Net annual production volumes: | ||||
Natural gas (mmcf)(1) | 2,049 | |||
| Oil (mbbls) | — | |||
| Total (mmcfs) | 2,049 | |||
| Average sales price: | ||||
| Natural gas (per mcf) | $ | 8.55 | ||
| Oil (per bbl) | $ | — | ||
Other financial information: | ||||
| Net cash used in operating activities | $ | — | ||
| Capital expenditures | $ | 70,883,000 | ||
EBITDA(2) | $ | 3,300 | ||
| For the period July 21, 2006 | ||||
| (date of formation) | ||||
| through December 31, 2006 | ||||
Balance sheet data: | ||||
| Total assets | $ | 72,473,100 | ||
| Total liabilities | $ | 345,400 | ||
| Partners’ capital | $ | 72,127,700 | ||
| (1) | Excludes sales of residual gas and sales to landowners. | |
| (2) | We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States of America or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our participants to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation from, or as a substitute for, our net income as an indicator of operating performance or cash flows from |
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| operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our income from continuing operations for the periods indicated. |
| For the period July 21, 2006 | ||||
| (date of formation) | ||||
| through December 31, 2006 | ||||
| Loss from continuing operations | $ | (700 | ) | |
| Plus depletion | 4,000 | |||
| EBITDA | $ | 3,300 | ||
Forward-Looking Statements.When used in this Form 10, the words “believes,” “anticipates,” “expects” and similar expressions are intended to identify forward-looking statements. These statements are subject to certain risks and uncertainties more particularly described in Item 1A “Risk Factors” of this Form 10. These risks and uncertainties could cause our actual results to differ materially from those that we anticipate. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Form 10. We undertake no obligation to publicly release the results of any revisions to forward-looking statements that we may make to reflect events or circumstances after the date of this Form 10 or to reflect the occurrence of unanticipated events.
This Item 2 “Financial Information” section should be read in conjunction with Item 13 “Financial Statements and Supplementary Data – Notes to Financial Statements.”
Results of Operations.The following table sets forth information for the period July 21, 2006 (date of formation) through December 31, 2006 relating to revenues recognized and costs and expenses incurred, daily production volumes, average sales prices and production cost per equivalent unit during the period indicated:
| Period Ended | ||||
| December 31, 2006 | ||||
| Revenues (in thousands): | ||||
Gas(1) | $ | 17,500 | ||
| Oil | $ | — | ||
| Production volumes: | ||||
| Gas (thousands of cubic feet (mcf)/day) | 98 | |||
| Oil (barrels (bbls)/day) Average sales price: | — | |||
| Gas (per mcf) | $ | 8.55 | ||
| Oil (per bbl) | $ | — | ||
| Production costs: | ||||
| As a percent of sales | 12 | % | ||
| Per equivalent mcf | $ | 1.04 | ||
| Depletion per mcfe | $ | 1.95 | ||
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| (1) | Excludes sales of residual gas and sales to landowners. |
Liquidity and Capital Resources.Cash used in investing activities was $70,883,000 for the period ended December 31, 2006, which was paid to our managing general partner, serving as general drilling contractor, pursuant to our drilling and operating agreement. Cash provided by financing activities was $70,883,100 which came from capital contributions for the period ended December 31, 2006.
Our managing general partner believes that we have adequate capital to develop approximately 256 gross wells under our drilling and operating agreement. Our wells will be drilled primarily in western Pennsylvania and Tennessee. Funds contributed by our participants and our managing general partner after our formation will be the only funds available to us for drilling activities, and no other wells will be drilled after this initial group. Although we estimate that 256 gross development wells will be drilled, we cannot guarantee that all of our proposed wells will be drilled or completed. Each of our proposed wells is unique and the ultimate costs incurred may be more or less than our current estimates.
Our ongoing operating and maintenance costs for the next 12-month period are expected by our managing general partner to be fulfilled through revenues from the sale of our gas and oil production. Although we do not anticipate that there will be a shortfall in our revenues that we use to pay for our ongoing expenses, if one were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, which are not contractually committed to make a loan. The amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings will be obtained from third-parties.
We have not and will not devote any funds to research and development activities and no new products or services will be introduced. We do not plan to sell any of our wells and intend to continue to produce them until they are depleted at which time they will be plugged and abandoned. We have no employees and rely on our managing general partner for management.
Critical Accounting Policies.The discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and costs and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to oil and gas reserves and certain accrued liabilities. We base our estimates on our managing general partner’s historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
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We have identified the following policies as critical to our business operations and understanding the results of our operations. For a detailed discussion on the application of these and other accounting policies, see Note 2 in Item 13 “Financial Statements and Supplementary Data – Notes to Financial Statements.”
Use of Estimates. Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates.
Reserve Estimates. Our estimates of our proved natural gas and oil reserves and our future net revenues from them will be based on reserve analyses that rely on various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, abandonment costs, 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 our proved natural gas and oil reserves will be 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 the estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based on production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.
Impairment of Oil and Gas Properties. We will review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We will estimate the expected future cash flows from our oil and gas properties and compare the future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties and impairments may be required in the future.
Dismantlement, Restoration, Reclamation and Abandonment Costs. On a periodic basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of equipment recoverable on abandonment. We account for
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abandonment costs using SFAS 143, “Accounting for Asset Retirement Obligations,” as discussed in Note 3 to our consolidated financial statements in Item 13 “Financial Statements and Supplementary Data – Notes to Financial Statements.” As of December 31, 2006, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or cost, could reduce our gross profit from energy operations.
Commodity Price Risk. Our major market risk exposure in commodities is fluctuations in the pricing of our natural gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use hedges. Our managing general partner through its hedges seeks to provide a measure of stability in the volatile environment of natural gas prices. Our risk management objective is to lock in a range of pricing for expected production volumes.
Third-party marketers to which we sell natural gas also use financial hedges to hedge their pricing exposure and make price hedging opportunities available to us. These transactions are similar to NYMEX- based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point. In the future, we estimate a significant amount of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. We also negotiate with certain purchasers for delivery of a portion of natural gas we will produce for the upcoming twelve months. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based.
ITEM 3. PROPERTIES.
Drilling Activity.As of December 31, 2006 we had drilled 44 gross wells, which is 41.63 net wells, and 6 of those wells were online for the sale of production as shown in the following table. All of the wells we drilled were “development wells,” which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. In addition to the wells we drilled during 2006, our participants’ share of our estimated drilling and equipment costs of approximately 188.13 net wells were prepaid by us in 2006. The drilling of each of the wells we prepaid in 2006 began on or before March 31, 2007, and those prepaid wells are not included in the following table.
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| Development Wells | ||||||||||||||||
| Productive (1) | Dry (2) | |||||||||||||||
| Gross (3) | Net (4) | Gross (3) | Net (4) | |||||||||||||
Period Ending December 31, 2006 | 6 | 6 | — | — | ||||||||||||
| (1) | A “productive well” generally means a well that is not a dry hole. | |
| (2) | A “dry hole” generally means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. The term “completion” refers to the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency. | |
| (3) | A “gross” well is a well in which we own 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. |
Summary of Productive Wells.The table below shows the location by state and the number of productive gross and net wells in which we owned a working interest at December 31, 2006. All of our wells are classified as natural gas wells.
| Location | Gross | Net | ||||||
| Pennsylvania | 6 | 6 | ||||||
| Tennessee | ¯ | ¯ | ||||||
| Total | 6 | 6 | ||||||
Production.The following table shows the quantities of natural gas and oil produced (net to our interest), average sales price, and average production (lifting) cost per equivalent unit of production for the period indicated.
| Production | Average Production | |||||||||||||||||||
| Gas | Average Sales Price | Cost (Lifting Cost) | ||||||||||||||||||
| Oil (bbls) | (mcf) | per bbl | per mcf (1) | per mcfe (1)(2) | ||||||||||||||||
Period from First Production to December 31, 2006 | — | 2,000 | $ | — | $ | 8.55 | $ | 1.04 | ||||||||||||
| (1) | “Mcf” means one thousand cubic feet of natural gas. “Mcfe” means one thousand cubic feet equivalent. | |
| “Bbl” means one barrel of oil. Oil production is converted to mcfe at the rate of six mcf per barrel (“bbl”). | ||
| (2) | Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, gathering charges and production overhead. |
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Natural Gas and Oil Reserve Information.The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. As of December 31, 2006 we had drilled 44 gross wells, which is 41.63 net wells, and 6 of those wells were online for the sale of production as shown in the following table. All of the wells we drilled were “development wells,” which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. In addition to the wells we drilled during 2006, our participants’ share of our estimated drilling and equipment costs of approximately 188.13 net wells were prepaid by us in 2006. The drilling of each of the wells we prepaid in 2006 began on or before March 31, 2007, and those prepaid wells are not included in the following table. Thus, the reserve information set forth below is not necessarily representative of our reserves after all of our wells are drilled and completed. All of our reserves are located in the United States. The information on our proved natural gas and oil reserves was prepared by Wright & Company, Inc., independent energy consultants. In accordance with SEC guidelines, we make the SEC PV-10 estimates of future net cash flows from proved reserves using natural gas sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We based our estimates of proved reserves on the following year-end weighted average prices, which does not reflect the effects of the financial hedges.
At December 31, 2006
| Natural gas (per mcf) | $ | 6.26 | ||
| Oil (per bbl) | $ | 57.25 |
Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves, of necessity, are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports prepared by Wright & Company, Inc., independent energy consultants.
Results of drilling, testing and production after the date of the estimate may justify revising the estimate. Future prices received from the sale of natural gas may be different from those we estimated in preparing our reports. The amounts and timing of future operating, development and abandonment costs may also differ from those used. Thus, 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 values as representative of the fair market value of our proved natural gas properties. PV-10 values are based on projected cash inflows, which do not provide for changes in natural gas and oil prices or for escalation of expenses and capital costs. The meaningfulness of these estimates depends on the accuracy of the assumptions on 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. In arriving at the estimated future cash flows, we deducted when applicable the operating costs, development costs, and production-related and ad valorem taxes. We made no provision for income taxes, and based the estimates on operating methods and conditions prevailing as of the dates indicated. We cannot assure you that these estimates are accurate predictions of future net cash flows from natural gas reserves or their present value. For additional information concerning our natural gas reserves and estimates of future net revenues, see Item 13 “Financial Statements and Supplementary Data – Notes to Financial Statements.”
| At December 31, 2006 | ||||
| Natural gas reserves – Proved Reserves (Mcf)(1)(4): | ||||
| Proved developed reserves (2) | 2,841,800 | |||
| Total proved reserves of natural gas | 2,841,800 | |||
| Oil reserves – Proved Reserves (Bbl)(1)(4): | ||||
| Proved developed reserves (2) | 2,300 | |||
| Total proved reserves of oil | 2,300 | |||
| Total proved reserves (Mcfe) | 2,855,600 | |||
| PV-10 estimate of cash flows of proved reserves (3)(4): | ||||
| Proved developed reserves | $ | 1,252 | ||
| Total PV-10 estimate | $ | 2,150 | ||
| (1) | “Proved reserves” generally means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements, but not escalations based on future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. | |
| (2) | “Proved developed oil and gas reserves” generally means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. | |
| (3) | The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually. | |
| (4) | Please see Regulation S-X rule 4-10 for complete definitions of each reserve category. |
We have not filed any estimates of our natural gas and oil reserves with, nor were the estimates included in any reports to, any Federal or foreign governmental agency within the 12 months before the date of this filing. For additional information concerning our natural gas and oil reserves and activities, see Item 13 “Financial Statements and Supplementary Data – Notes to Financial Statements.”
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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 and oil 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 and oil industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we begin drilling operations, however, we conduct an extensive title examination and perform curative work on any defects that we deem significant. We have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry, such as free gas to the landowner-lessor for home heating requirements, etc. 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 shows the estimated acres of developed and undeveloped natural gas and oil acreage in which we have an interest, separated by state, at December 31, 2006.
| Developed Acreage | Undeveloped Acreage (3) | |||||||||||||||
| Location | Gross (1) | Net (2) | Gross (1) | Net (2) | ||||||||||||
| New York | — | — | 200.00 | 200.00 | ||||||||||||
| Pennsylvania | 838.01 | 835.51 | 3,330.25 | 3,136.18 | ||||||||||||
| Tennessee | 320.00 | 210.00 | 2,080.00 | 1,662.50 | ||||||||||||
| Total | 1,158.01 | 1,045.51 | 5,610.25 | 4,998.68 | ||||||||||||
| (1) | A “gross” acre is an acre in which we own a working interest. | |
| (2) | A “net” acre equals 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 natural gas and oil regardless of whether or not the acreage contains proved reserves. |
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As discussed in Item 1 “Business – General – Sale of Natural Gas and Oil Production,” we are not required to provide any fixed and determinable quantities of natural gas under any agreement.
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
As of December 31, 2006, we had issued 2,840 Units to 1,359 participants. The following table, as of December 31, 2006, sets forth the number and percentage of Units owned and held by:
| • | beneficial owners of 5% or more of our Units; | ||
| • | our managing general partner’s executive officers and directors; and | ||
| • | all of the executive officers and directors of our managing general partner as a group. |
The address for each director and executive officer of our managing general partner is 311 Rouser Road, Moon Township, Pennsylvania 15108.
| Units | ||||||||
| Amount and Nature | ||||||||
| of Beneficial | ||||||||
| Beneficial Owner | Ownership | Percent of Class | ||||||
DIRECTORS AND EXECUTIVE OFFICERS | ||||||||
| Freddie M. Kotek | 0 | 0 | % | |||||
| Frank P. Carolas | 0 | 0 | % | |||||
| Jeffrey C. Simmons | 0 | 0 | % | |||||
| Michael L. Staines | 0 | 0 | % | |||||
NON-DIRECTOR EXECUTIVE OFFICERS | ||||||||
| Jack L. Hollander | 0 | 0 | % | |||||
| Matthew A. Jones | 0 | 0 | % | |||||
| Nancy J. McGurk | 0 | 0 | % | |||||
| Michael G. Hartzell | 0 | 0 | % | |||||
| Donald R. Laughlin | 0 | 0 | % | |||||
| Karen A. Black | 0 | 0 | % | |||||
| Marci F. Bleichmar | 0 | 0 | % | |||||
| All executive officers and directors as a group. | 0 | 0 | % | |||||
OTHER OWNERS OF MORE THAN 5% OF OUTSTANDING UNITS | ||||||||
| None | 0 | 0 | % | |||||
We are not aware of any arrangements which may, at a subsequent date, result in a change in our control.
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ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS
Managing General Partner.We have no officers, directors or employees. Instead, Atlas Resources, LLC, a Pennsylvania limited liability company, which was originally formed as a corporation in 1979 and then changed to a limited liability company on March 28, 2006, serves as our managing general partner. Our managing general partner depends on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for all management and administrative functions and financing for capital expenditures. Our managing general partner paid a management fee of 7% of subscription funds raised to Atlas America, and reimbursed Atlas America for, management and administrative services and expenses incurred on its behalf based on an allocation of total revenues.
In addition, Atlas America (ATLS) transferred to Atlas Energy Resources, LLC (ATN), a newly-formed, limited liability company subsidiary of Atlas America, substantially all of its natural gas and oil exploration and production assets in December 2006 pursuant to the completion of an initial public offering of 7,273,750 of Atlas Energy Resources, LLC’s Class B limited liability company interests. At the conclusion of the offering, pursuant to the contribution, conveyance and assumption agreement among Atlas America, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC, Atlas America contributed to Atlas Energy Resources, LLC all of the stock of Atlas America’s natural gas and oil development and production subsidiaries as well as the development and production assets owned by it. As consideration for this contribution, on December 18, 2006 Atlas Energy Resources, LLC distributed to Atlas America $139,944,000 net proceeds of the offering, 29,352,996 of common units, 748,456 Class A units, and the management incentive interests. Also pursuant to the contribution agreement, Atlas America contributed to its subsidiary, Atlas Energy Management, Inc. (“Atlas Management”), the 748,456 Class A units and the management incentive interests. Atlas America retained approximately 81% of the limited liability company interests of Atlas Energy Resources, LLC, which will continue to provide Atlas America control over Atlas Energy Resources, LLC and its assets and business.
Until December 18, 2007, Atlas America will indemnify Atlas Energy Resources, LLC against certain potential environmental liabilities associated with the operation of the assets and occurring before December 18, 2006. The obligation of the indemnitors will not exceed $25 million, and they will not have any indemnification obligation until Atlas Energy Resources, LLC’s losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000. Additionally, Atlas America will indemnify Atlas Energy Resources, LLC for
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losses attributable to title defects to the oil and gas property interests until December 18, 2009, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and the formation transactions. Atlas Energy Resources, LLC will indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to it, to the extent not subject to Atlas America’s indemnification obligations.
In addition, Atlas Energy Resources, LLC became a party to an existing master natural gas gathering agreement between Atlas America and Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P. (collectively, “Atlas Pipeline”) pursuant to which Atlas Pipeline will gather substantially all of the natural gas from wells operated by Atlas Energy Resources, LLC. The gathering fees payable to Atlas Pipeline under the master natural gas gathering agreement are generally greater than the gathering fees paid by us or our managing general partner’s other partnerships for gathering. Pursuant to the contribution agreement, Atlas America will assume Atlas Energy Resources, LLC’s obligation to pay these gathering fees to Atlas Pipeline; and Atlas Energy Resources, LLC will pay Atlas America the gathering fees it receives from us and our managing general partner’s other partnership and fees associated with production to its interest.
Further, Atlas America and Atlas Energy Resources, LLC entered into an omnibus agreement, which provides that if a business opportunity with respect to an investment in or acquisition of a domestic natural gas or oil production or development business is presented to Atlas Energy Resources, LLC or Atlas America or its affiliates, Atlas Energy Resources, LLC will have the first right to pursue the business opportunity as follows:
| • | If the opportunity is a control investment, that is, majority control of the voting securities of an entity, Atlas Energy Resources, LLC will have the first right of refusal. | ||
| • | If the opportunity is a non-control investment, that is, less than majority control of the voting securities of an entity, Atlas America and its affiliates will not be restricted in their ability to pursue the opportunity and will not have an obligation to present the opportunity to Atlas Energy Resources, LLC. | ||
| • | Notwithstanding the foregoing, if the opportunity involves an investment in natural gas or oil wells or other natural gas or oil rights, even a non-control investment, Atlas Energy Resources, LLC will have the right of first refusal. |
The omnibus agreement will remain in effect so long as Atlas America or one of its affiliates has the power, directly or indirectly, to direct Atlas Energy Resources, LLC’s management and policies.
In September 1998, Atlas Energy Group, Inc., the former parent company of our managing general partner, merged into Atlas America, Inc., a Delaware holding company, which was a subsidiary of Resource America, Inc., a publicly-traded company. In May 2004 Resource America conducted a public offering of a portion of its
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common stock (the “shares”) in Atlas America. Two million six hundred forty-five thousand shares were registered and sold at a price of at $15.50 per share resulting in gross proceeds of $41 million. Further, in May 2004, in connection with the Atlas America offering, the following officers and key employees of our managing general partner and Atlas America set forth in “– Officers, Directors and Other Key Personnel of Managing General Partner,” below, resigned their positions with Resource America and all of its subsidiaries that are not also subsidiaries of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines, and Ms. Marci Bleichmar. After the public offering, Resource America continued to own approximately 80.2% of Atlas America’s common stock until it distributed all of its remaining 10.7 million shares of common stock in Atlas America to its common stockholders on June 30, 2005. The distribution was in the form of a spin-off by means of a tax free dividend of approximately 0.6 shares of Atlas America to Resource America common stockholders for each share of Resource America common stock owned. Resource America’s rights following the distribution are defined by agreements between Resource America and Atlas America.
Atlas America and Atlas Energy Resources, LLC are headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport, which is also our managing general partner’s primary office.
Officers, Directors and Other Key Personnel of Managing General Partner
The officers and directors of our managing general partner will serve until their successors are elected. The officers, directors, and key personnel of our managing general partner are as follows:
The officers and directors of our managing general partner will serve until their successors are elected. The officers, directors, and key personnel of our managing general partner are as follows:
| NAME | AGE | POSITION OR OFFICE | ||||
| Freddie M. Kotek | 50 | Chairman of the Board of Directors, Chief Executive Officer and President | ||||
| Frank P. Carolas | 47 | Executive Vice President – Land and Geology and a Director | ||||
| Jeffrey C. Simmons | 48 | Executive Vice President – Operations and a Director | ||||
| Jack L. Hollander | 50 | Senior Vice President – Direct Participation Programs | ||||
| Matthew A. Jones | 45 | Chief Financial Officer | ||||
| Nancy J. McGurk | 50 | Senior Vice President and Chief Accounting Officer | ||||
| Michael L. Staines | 57 | Senior Vice President, Secretary and a Director | ||||
| Michael G. Hartzell | 51 | Vice President – Land Administration | ||||
| Donald R. Laughlin | 58 | Vice President – Drilling and Production | ||||
| Marci F. Bleichmar | 36 | Vice President of Marketing | ||||
| Sherwood S. Lutz | 55 | Senior Geologist/Manager of Geology | ||||
| Michael W. Brecko | 48 | Director of Energy Sales | ||||
| Karen A. Black | 46 | Vice President – Partnership Administration | ||||
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| NAME | AGE | POSITION OR OFFICE | ||||
| Justin T. Atkinson | 33 | Director of Due Diligence | ||||
| Winifred C. Loncar | 65 | Director of Investor Services | ||||
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 managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc. have been aggregated.
Freddie M. Kotek.President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has been Executive Vice President of Atlas America since February 2004, and served as a director from September 2001 until February 2004 and served as Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August 1999. Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors in Economics. He also received a Master in Business Administration degree from the Harvard Graduate School of Business Administration in 1981. Mr. Kotek devotes approximately 95% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of our managing general partner’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 our managing general partner 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 our managing general partner. Mr. Carolas is a certified petroleum geologist and has been with our managing general partner 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 our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
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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 our managing general partner 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 in Petroleum Engineering 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 our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of our managing general partner’s other affiliates, primarily Viking Resources and Resource Energy.
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 our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Matthew A. Jones, Chief Financial Officer since March 2006. Mr. Jones has been Chief Financial Officer since January 2006 and a director since February 2006 of Atlas Pipeline Holdings, L.P., and has been the Chief Financial Officer of Atlas Pipeline Partners GP and Atlas America since March 2005. He has been the Chief Financial Officer and a director of Atlas Energy Resources and Atlas Energy Management since their formation. 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 is a Chartered Financial Analyst.
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Nancy J. McGurk.Senior Vice President since January 2002 and Chief Accounting Officer since January 2001. Ms. McGurk also serves as Senior Vice President since January 2002 and Chief Accounting Officer of Atlas America since January 2001. Ms. McGurk has been Chief Accounting Officer of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. since 2006. Ms. McGurk served as Chief Financial Officer for Atlas America from January 2001 until February 2004. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004 and its Treasurer and Chief Accounting Officer from 1989 until May 2004 when she resigned from Resource America. Also, since 1995 Ms. McGurk has served as Vice President – Finance of Resource Energy, Inc. Ms. McGurk received a Bachelor of Science degree in Accounting from Ohio State University in 1978, and has been a Certified Public Accountant since 1982. Ms. McGurk devotes approximately 80% of her professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of her professional time to the business and affairs of our managing general partner’s other affiliates.
Michael L. Staines.Senior Vice President, Secretary, and a Director since 1998. Mr. Staines has been an Executive Vice President and Secretary of Atlas America since 1998. Mr. Staines was a Senior Vice President of Resource America from 1989 until May 2004 when he resigned from Resource America. Mr. Staines was a director of Resource America from 1989 to February 2000 and Secretary from 1989 to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation in November 1999. Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent Oil and Gas Association of New York. Mr. Staines received a Bachelor of Science degree from Cornell University in 1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines devotes approximately 5% of his professional time to the business and affairs of our managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of our managing general partner’s other affiliates, including Atlas Pipeline Partners GP.
Michael G. Hartzell.Vice President – Land Administration since September 2001. Mr. Hartzell has been Vice President – Land Administration of Atlas America since January 2002, and before that served as Senior Land Coordinator from January 1999 to January 2002. Mr. Hartzell has been Vice President – Land Administration of Atlas Energy Management, Inc. since 2006. Mr. Hartzell has been with our managing general partner and its affiliates since 1980 when he began his career as a land department representative. Mr. Hartzell manages all Land Department functions. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr. Hartzell received his Bachelor of Science degree in Business Management from the University of Phoenix in 2004. Mr. Hartzell devotes approximately 100% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
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Donald R. Laughlin.Vice President – Drilling and Production since September 2001. Mr. Laughlin also serves as Vice President – Drilling and Production for Atlas America since January 2002, and before that served as Senior Drilling Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has been Vice President – Drilling and Production of Atlas Energy Management, Inc. since 2006. Mr. Laughlin has over thirty years of experience as a petroleum engineer in the Appalachian Basin, having been employed by Columbia Gas Transmission Corporation from October 1995 to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical Services, Doran & Associates, Inc. from 1977 until 1989 as Vice President—Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree from the University of Pittsburgh in 1970. He is a member of the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Marci F. Bleichmar.Vice President of Marketing since February 2001. Ms. Bleichmar also serves as Vice President of Marketing for Atlas America since February 2001 and was with Resource America from February 2001 until May 2004 when she resigned from Resource America. From March 2000 until February 2001, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms. Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in 1992. Ms. Bleichmar devotes approximately 100% of her professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Sherwood S. Lutz.Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined Viking Resources, which was purchased by Resource America in 1999 as senior geologist. Since 1999 Mr. Lutz has been a senior geologist for our managing general partner and Atlas America. Mr. Lutz received his Bachelor of Science degree in Geological Sciences from the Pennsylvania State University in 1973. Mr. Lutz is a certified petroleum geologist with the American Association of Petroleum Geologists as well as a licensed professional geologist in Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, LLC.
Michael W. Brecko.Director of Energy Sales since November 2002. Mr. Brecko has over 19 years of natural gas marketing experience in the oil and natural gas industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University with a Bachelor of Science degree in Civil Engineering. His career in natural gas marketing began when he joined Equitable Gas Company, a local distribution company, as a marketing representative in the commercial/ industrial marketing division from May 1986 to August 1992. He subsequently joined O&R Energy, a subsidiary of Orange and Rockland Utilities, as regional marketing manager from August
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1992 to November 1993. Beginning in December 1993 through July 2001, Mr. Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and natural gas producer, as an account executive and he was promoted in August 1998 to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a multi-energy sourced company, as a regional account manager before joining Atlas America in 2002. Mr. Brecko devotes approximately 100% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Karen A. Black.Vice President – Partnership Administration since February 2003. Ms. Black is also Vice President and Financial and Operations Principal of Anthem Securities since October 2002. Ms. Black joined our managing general partner and Atlas America in July 2000 and served as manager of production, revenue and partnership accounting from July 2000 through October 2001, after which she served as manager and financial analyst until her appointment as Vice President – Partnership Administration. Before joining our managing general partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh, Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of her professional time to the business and affairs of Anthem Securities.
Justin T. Atkinson. Director of Due Diligence since February 2003. Mr. Atkinson also serves as President of Anthem Securities since February 2004 and as Chief Compliance Officer since October 2002. Before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from December 2001 until October 2002 and Vice President from October 2002 until February 2004. Before his employment with our managing general partner, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson devotes approximately 25% of his professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his professional time to the business and affairs of Anthem Securities.
Winifred C. Loncar, Director of Investor Services since February 2003. Ms. Loncar previously held the position of manager of investor services from the inception of the investor service department in 1990 to February 2003. Before that she was executive secretary to our managing general partner. Ms. Loncar received a Bachelor of Science degree in Business from Point Park University in 1998. Ms. Loncar devotes approximately 100% of her professional time to the business and affairs of our managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
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Organizational Diagram and Security Ownership of Beneficial Owners
Atlas America owns approximately 81% of the limited liability company interests 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 interests of our managing general partner. The officers and directors of Atlas America and Atlas Energy Resources, LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The biographies of Messrs. Staines and Simmons are set forth above.
[THE REST OF THIS PAGE INTENTIONALLY LEFT BLANK.]
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ORGANIZATIONAL DIAGRAM
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| (1) | On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned subsidiary of Atlas America, filed a registration statement with the SEC for an initial public offering of 3.6 million of its common units, which represented an approximate 17.1% limited partner interest in the company. On July 26, 2006, Atlas Pipeline Holdings, L.P. issued 3.6 million common units, representing a 17.1% ownership interest, in the initial public offering at a price of $23 per unit, and the underwriters were granted a 30-day option to purchase up to an additional 540,000 common units. Substantially all of the net proceeds from this offering, approximately $77 million, have been paid to Atlas America. Atlas America continues to own approximately 82.9% of Atlas Pipeline Holdings GP, LLC, which gives Atlas America indirect general partner control over Atlas Pipeline Partners (APL). |
Atlas America, Inc., a Delaware Company
As of August 24, 2006, the officers and directors for Atlas America include the following:
| NAME | AGE | POSITION | ||
| Edward E. Cohen | 67 | Chairman, Chief Executive Officer and President | ||
| Frank P. Carolas | 47 | Executive Vice President | ||
| Freddie M. Kotek | 50 | Executive Vice President | ||
| Jeffrey C. Simmons | 48 | Executive Vice President | ||
| Michael L. Staines | 57 | Executive Vice President and Secretary | ||
| Matthew A. Jones | 45 | Chief Financial Officer | ||
| Nancy J. McGurk | 50 | Senior Vice President and Chief Accounting Officer | ||
| Jonathan Z. Cohen | 36 | Vice Chairman | ||
| Carlton M. Arrendell | 44 | Director | ||
| William R. Bagnell | 43 | Director | ||
| Donald W. Delson | 55 | Director | ||
| Nicholas DiNubile | 54 | Director | ||
| Dennis A. Holtz | 66 | Director | ||
| Harmon S. Spolan | 70 | Director |
See “– Officers, Directors and Other Key Personnel of Managing General Partner,” above, for biographical information on certain of these individuals who are also officers of our managing general partner. Biographical information on the other officers and directors will be provided by our managing general partner on request.
Our managing general partner and its affiliates under Atlas America employ more than 205 persons.
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Atlas Energy Resoures, LLC, a Delaware Limited Liability Company
As of December 12, 2006, the directors, nominees and executive officers for Atlas Energy Resources, LLC include the following:
| NAME | AGE | POSITION OR OFFICE | ||
| Edward E. Cohen | 67 | Chairman of the Board and Chief Executive Officer | ||
| Jonathan Z. Cohen | 36 | Vice Chairman of the Board | ||
| Richard D. Weber | 43 | President, Chief Operating Officer and Director | ||
| Matthew A. Jones | 45 | Chief Financial Officer and Director | ||
| Nancy J. McGurk | 50 | Chief Accounting Officer | ||
| Lisa Washington | 39 | Chief Legal Officer and Secretary | ||
| Walter C. Jones | 43 | Director | ||
| Ellen F. Warren | 50 | Director | ||
| Bruce M. Wolf | 58 | Director |
See “– Officers, Directors and Other Key Personnel of Managing General Partner,” above, for biographical information on Ms. McGurk and Mr. Matthew A. Jones, who also are officers of our managing general partner. Also, on May 9, 2006 Mr. Richard Weber was appointed President, Chief Operating Officer and a director of Atlas Energy Resources, LLC. In conjunction with Mr. Weber’s appointment, Atlas America and Mr. Weber entered into an employment agreement dated April 5, 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc. As part of his duties, he oversaw the bank’s activities with oil and gas producers, pipeline companies and utilities. He has a particular expertise in the Appalachian Basin, where he led over 40 transactions, including the IPOs of Atlas America and Atlas Pipeline and the sale of Viking Resources Corporation to Atlas America.
Biographical information on the other officers and directors of Atlas Energy Resources, LLC will be provided by our managing general partner on request.
Atlas Energy Management, Inc., a Delaware Company
As of July 28, 2006, the officers for Atlas Energy Management, Inc. include the following:
| NAME | AGE | POSITION OR OFFICE | ||
| Edward E. Cohen | 67 | Chairman of the Board and Chief Executive Officer | ||
| Richard D. Weber | 43 | President, Chief Operating Officer and Director | ||
| Jeffrey C. Simmons | 48 | Senior Vice President | ||
| Frank P. Carolas | 47 | Senior Vice President |
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| NAME | AGE | POSITION OR OFFICE | ||
| Matthew A. Jones | 45 | Chief Financial Officer | ||
| Nancy J. McGurk | 50 | Chief Accounting Officer | ||
| Donald R. Laughlin | 58 | Vice President – Drilling and Production | ||
| Michael G. Hartzell | 51 | Vice President – Land Administration | ||
| Lisa Washington | 39 | Chief Legal Officer and Secretary |
See “– Officers, Directors and Other Key Personnel of Managing General Partner,” above, for biographical information on certain of these individuals who are also officers of our managing general partner. Biographical information on the other officers and directors will be provided by our managing general partner on request.
Remuneration of Officers and Directors
No officer or director of our managing general partner will receive any direct remuneration or other compensation from us. These persons will receive compensation solely from affiliated companies of our managing general partner.
Code of Business Conduct and Ethics
Because we do not directly employ any persons, our managing general partner has determined that we will rely on a Code of Business Conduct and Ethics adopted by Atlas America, Inc. and/or Atlas Energy Resources, LLC that applies to the principal executive officer, principal financial officer and principal accounting officer of our managing general partner, as well as to persons performing services for our managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to our managing general partner at Atlas Resources, LLC, 311 Rouser Road, Moon Township, Pennsylvania 15108.
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Atlas Management will provide Atlas Energy Resources, LLC and its subsidiaries, including our managing general partner, with all services necessary or appropriate for the conduct of their business, including the following:
| • | providing executive and administrative personnel, office space and office services required in rendering services to Atlas Energy Resources, LLC and its subsidiaries; | ||
| • | investigating, analyzing and proposing possible acquisition and investment opportunities; | ||
| • | evaluating and recommending to the board and Atlas Energy Resources, LLC’s officers hedging strategies and engaging in hedging activities on Atlas Energy Resources, LLC’s behalf, consistent with such strategies; | ||
| • | negotiating agreements on Atlas Energy Resources, LLC’s behalf; | ||
| • | at the direction of the audit committee of the board, causing Atlas Energy Resources, LLC to retain qualified accountants to assist in developing appropriate accounting procedures, compliance procedures and testing systems with respect to financial reporting obligations, and to conduct quarterly compliance reviews with respect thereto; | ||
| • | causing Atlas Energy Resources, LLC to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses; | ||
| • | assisting Atlas Energy Resources, LLC in complying with all regulatory requirements applicable to it with respect to its business activities, including preparing or causing to be prepared all financial statements required under applicable regulations and contractual undertakings, all required tax filings and all reports and documents, if any, required under the Securities Exchange Act; | ||
| • | handling and resolving all claims, disputes or controversies (including all litigation, arbitration, settlement or other proceedings or negotiations) in which Atlas Energy Resources, LLC may be involved or to which it may be subject arising out of its day-to-day operations, subject to such limitations or parameters as may be imposed from time to time by the board; | ||
| • | advising Atlas Energy Resources, LLC with respect to obtaining financing for Atlas Energy Resources, LLC’s operations; |
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| • | performing such other services as may be required from time to time for management and other activities relating to Atlas Energy Resources, LLC’s assets as the board reasonably requests or Atlas Management deems appropriate under the particular circumstances; | ||
| • | obtaining and maintaining, on Atlas Energy Resources, LLC’s behalf, insurance coverage for Atlas Energy Resources, LLC’s business and operations, including errors and omissions insurance with respect to the services provided by Atlas Management, in each case in the types and minimum limits as Atlas Management determines to be appropriate and as is consistent with standard industry practice; and | ||
| • | using commercially reasonable efforts to cause Atlas Energy Resources, LLC to comply with all applicable laws. |
In exercising its powers and discharging its duties under the management agreement, Atlas Management must act in good faith.
Atlas Energy Resources, LLC will reimburse Atlas Management for all expenses that it incurs on Atlas Energy Resources, LLC’s behalf pursuant to the management agreement. These expenses will include costs for providing corporate staff and support services to Atlas Energy Resources, LLC and its subsidiaries, including our managing general partner and its partnerships, which includes us. Atlas Management will charge on a fully-allocated cost basis for services provided to Atlas Energy Resources, LLC. This fully-allocated cost basis is based on the percentage of time spent by personnel of Atlas Management and its affiliates on Atlas Energy Resources, LLC’s matters and includes the compensation paid by Atlas Management and its affiliates to such persons and their allocated overhead. The allocation of compensation expense for such persons will be determined based on a good faith estimate of the value of each such person’s services performed on Atlas Energy Resources, LLC’s business and affairs, subject to the periodic review and approval of the board’s audit or conflicts committee.
Atlas Management, its stockholders, directors, officers, employees and affiliates will not be liable to Atlas Energy Resources, LLC, and any subsidiary of Atlas Energy Resources, LLC for acts or omissions performed in good faith and in accordance with and pursuant to the management agreement, except by reason of acts constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law. Atlas Energy Resources, LLC will indemnify Atlas Management, its stockholders, directors, officers, employees and affiliates for all expenses and losses arising from acts of Atlas Management, its stockholders, directors, officers, employees and affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law performed in good faith in accordance with and pursuant to the management agreement. Atlas Management and its affiliates will indemnify Atlas Energy Resources, LLC for all expenses
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and losses arising from acts of Atlas Management or its affiliates not constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of Atlas Management or its affiliates relating to the terms and conditions of their employment. Atlas Management and/or Atlas America will carry errors and omissions and other customary insurance.
The management agreement may not be amended without the prior approval of the conflicts committee of the board if the proposed amendment will, in the reasonable discretion of the board, adversely affect common unitholders. The management agreement does not have a specific term; however, Atlas Management may not terminate the agreement before December 18, 2016. Atlas Energy Resources, LLC may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of its outstanding common units, including units held by Atlas America and its affiliates. If Atlas Energy Resources, LLC terminates the management agreement, Atlas Management will have the option to require the successor manager, if any, to purchase the Class A units and management incentive interests for their fair market value as determined by agreement between the departing manager and the successor manager.
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Oil and Gas Revenues.Our managing general partner currently is allocated 32.6% of our natural gas and oil revenues in return for paying and contributing services towards our organization and offering costs estimated to be 12% of our subscriptions, paying an estimated 70% of the tangible costs of our wells and contributing all of the leases covering each of our prospects on which one well is situated. As of December 31, 2006 we contributed $1,245,300 and estimate our total capital contributions to be $24,394,100.
Financial. During the period ended December 31, 2006, we did not pay any cash distributions to our managing general partner or our participants.
Leases.During the period ended December 31, 2006, our managing general partner contributed undeveloped prospects (leases) to us to drill 41.63 net wells, and received a credit to its capital account in us in the amount of $350,100. Our managing general partner anticipates entering into further lease transactions with us.
Administrative Costs.Our managing general partner and its affiliates receive an unaccountable, fixed payment reimbursement from us for their administrative costs of $75 per well per month, which will be proportionately reduced if we acquire less than 100% of the working interest in a well. Our managing general partner received $100 in these fees for the period ended December 31, 2006.
Direct Costs.Our managing general partner and its affiliates will be reimbursed by us for all direct costs expended by them on our behalf, whether our managing general partner is acting as our managing general
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partner or as the operator of our wells. For the period ended December 31, 2006, we reimbursed our managing general partner $11,900 for these direct costs.
Drilling Contracts.We entered into a drilling and operating agreement with our managing general partner, acting as our general drilling contractor, after our initial and final closing dates to drill and complete 229.76 net wells. The total amount received by our managing general partner from our subscription proceeds was $70,883,000. This amount was paid by our participants for their share of the costs of drilling and completing the wells, including the wells that were prepaid in 2006, but the drilling of which was to begin on or before March 31, 2007. We have not entered into any other drilling transactions to the date of this filing, and none are anticipated by us for future periods.
Per Well Charges.Our managing general partner, serving as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf as set forth above in “– Direct Costs” and receives well supervision fees for operating and maintaining our wells during producing operations in the amount of $362 per well per month subject to annual adjustments for inflation. During the period ended December 31, 2006, our managing general partner received $400 for well supervision fees.
Gathering Fees.We pay a gathering fee to our managing general partner at a competitive rate for each mcf transported. For the period ended December 31, 2006, the amount paid was $1,800. Of this amount, 100% was paid by our managing general partner to Atlas Pipeline Partners.
Dealer-Manager Fees.As part of the offering of our Units, our managing general partner’s affiliate, Anthem Securities, Inc., serving as dealer-manager of the offering, received a 2.5% dealer-manager fee, a 7% sales commission, a 1.5% nonaccountable marketing expense fee, and a .5% nonaccountable due diligence fee in the aggregate amount of $7,920,690. The dealer-manager will receive no further compensation from us. Of this amount, $4,858,140 was paid by Anthem Securities to third-party broker/dealers who participated in the offering of our Units.
Organization and Offering Costs.During the period ended December 31, 2006, our managing general partner paid and contributed services for our organization and offering costs in the amount of $8,506,000, including the compensation paid to the dealer-manager, which did not exceed 13% of our subscription proceeds.
Other Compensation.If our managing general partner makes a loan to us it may receive a competitive rate of interest. If our managing general partner provides equipment, supplies and other services to us, then it may do so at competitive industry rates. For the period ended December 31, 2006, no advances were made to us by our managing general partner and we did not enter into any contracts with our managing general partner for
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equipment, supplies and other services to us other than our partnership agreement and our drilling and operating agreement.
ITEM 8. LEGAL PROCEEDINGS.
None
ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Currently, there is no established public trading market for our Units.
As of December 31, 2006, there were no outstanding options or warrants to purchase, or securities convertible into, our Units. In addition, as of December 31, 2006, there were no Units that could be sold pursuant to Rule 144 under the Securities Act or that we had agreed to register under the Securities Act for sale by our participants and there were no Units that were being, or were publicly proposed to be, publicly offered by us.
As of December 31, 2006, there were 1,359 holders of records of our Units.
Our managing general partner reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed to our managing general partner and our participants, if any. Cash distributions to our managing general partner may only be made in conjunction with distributions to our participants and only out of funds properly allocated to our managing general partner’s account. We distribute those funds which our managing general partner determines are not necessary for us to retain, taking into account our managing general partner’s subordination obligation as described in Item 11 “Description of Registrant’s Securities to be Registered – Distributions and Subordination.” We will not advance or borrow funds for purposes of distributions to our participants if the amount of the distributions would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Distributions may be reduced or deferred to the extent our revenues are used for any of the following:
| • | repayment of borrowings; | ||
| • | cost overruns; | ||
| • | remedial work to improve a well’s producing capability; | ||
| • | our direct costs; | ||
| • | general and administrative expenses of our managing general partner; |
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| • | reserves, including a reserve for the estimated costs of eventually plugging and abandoning our wells; or | ||
| • | our indemnification of our managing general partner and its affiliates for losses or liabilities incurred in connection with our activities. |
The determination of our revenues and costs will be made in accordance with generally accepted accounting principles, consistently applied. During the period ended December 31, 2006, we made no cash distributions.
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES.
We sold 2,840 Units to 1,359 investors in a private placement offering of our Units beginning October 15, 2006 and ending December 29, 2006. Anthem Securities, Inc., an affiliate of our managing general partner, served as the dealer-manager of the offering and received the compensation set forth in Item 7 “Certain Relationships and Related Transactions – Dealer-Manager Fees.” Our net proceeds from the sale of our Units were $70,883,000.
We relied on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act in connection with the offering. Our Units were offered and sold to a limited number of persons who had the sophistication to understand the merits and risks of the investment, who had the financial ability to bear those risks, and who were “accredited investors,” as that term is defined in Regulation D (17 CFR 230.501(a)). All of our participants were reasonably believed by our managing general partner to be accredited investors at the time of sale.
ITEM 11. DESCRIPTION OF REGISTRANT’S SECURITIES TO BE REGISTERED.
General.The rights and obligations of the holders of our Units (i.e., our participants) are governed by our partnership agreement. “Units” means limited partner Units, investor general partner Units and the converted limited partner Units into which the investor general partner Units will be automatically converted by our managing general partner after all of our wells have been drilled and completed. The following discussion is a summary of some of the provisions of our partnership agreement that are related to the rights and obligations associated with the Units and is qualified in its entirety by the full text of the partnership agreement.
We were formed under the Delaware Revised Uniform Limited Partnership Act and are qualified to transact business in the jurisdictions where our wells are located. Our managing general partner is Atlas Resources, LLC, which has exclusive management control over all aspects of our business. In the course of its management, our managing general partner may, in its sole discretion, employ any persons, including its affiliates, as it deems necessary for our efficient operation.
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Liability of Participants for Further Calls and Conversion.We are governed by the Delaware Revised Uniform Limited Partnership Act. If a participant invested in us as a limited partner, then generally the participant will not be liable to third-parties for our obligations unless the participant:
| • | also invested in us as an investor general partner; | ||
| • | takes part in the control of our business in addition to the exercise of a participant’s rights and powers as a limited partner; or | ||
| • | fails to make a required capital contribution to the extent of the required capital contribution. |
In addition, a limited partner participant may be required to return any distribution received if the participant knew at the time the distribution was made that it was improper because it rendered us insolvent.
If the participant invested in us as an investor general partner for the tax benefits instead of as a limited partner, then his Units will be automatically converted by our managing general partner to limited partner Units after all of our wells have been drilled and completed. See Item 1 “Business.” Currently, the conversion has not occurred, because we have not yet drilled and completed all of our wells.
After the investor general partner Units are converted to limited partner Units, which is a nontaxable event, the participant will have the lesser liability of a limited partner under Delaware law for our obligations and liabilities that arise after the conversion, subject to the exceptions described above. However, an investor general partner will continue to have the responsibilities of a general partner for liabilities and obligations that we incurred before the effective date of the conversion. For example, an investor general partner might become liable for any liabilities we incurred in excess of his subscription amount during the time we engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. This could result in the former investor general partner being required to make payments, in addition to his original investment, in amounts that are impossible to predict because of their uncertain nature.
Distributions and Subordination.Our managing general partner will review our accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. Subject to our managing general partner’s subordination obligation as described below, our managing general partner and our participants share in all of our production revenues in the same percentage as their respective capital contribution bears to our total capital contributions, except that our managing general partner receives an additional 7% of our revenues. However, our managing general partner’s total revenue share may not exceed 40% of our revenues regardless of the amount of its capital contributions to us. As of December 31, 2006, our managing general partner received 32.6% of our production revenues and our participants received 67.4% of our production revenues. Subject to the foregoing, these sharing percentages will be adjusted based on the final
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amount of our managing general partner’s capital contributions to us after all of our wells have been drilled and completed. See our partnership agreement for special allocations between our managing general partner and our participants of equipment proceeds, lease proceeds and interest income.
Our partnership agreement is structured to provide our participants with cash distributions equal to a minimum of 10% of capital, based on a subscription price of $25,000 per Unit regardless of the actual subscription price paid by any participant for a Unit, in each of the first five 12-month periods beginning with our first cash distributions of revenues from operations. To help achieve this investment feature, under our partnership agreement our managing general partner will subordinate up to 50% of its share of our partnership net production revenues during this subordination period, which is up to 20% of our total partnership net production revenues. The term “partnership net production revenues” means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated in the partnership agreement. If our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination a participant may not receive the 10% return of capital for each of the first five years as described above, or a return of all of his capital during our term, because the subordination is not a guarantee.
Our 60-month subordination period will begin with our first cash distribution of revenues from operations in 2007. Subordination distributions will be determined by debiting or crediting our current period revenues to our managing general partner as may be necessary to provide the distributions to our participants. At any time during the subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent cash distributions from us exceed the 10% return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership agreement.
Participant Allocations.Our participants’ share as a group of our revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally are charged and credited among our participants in accordance with their respective number of Units, based on $25,000 per Unit regardless of the actual subscription price paid by any participant for a Unit. These allocations also take into account any investor general partner’s status as a defaulting investor general partner.
Certain participants, however, paid a reduced amount to acquire their Units. Thus, our intangible drilling costs and our participants’ share of our equipment costs to drill and complete our wells are charged among our participants in accordance with the respective subscription price they paid for their Units, rather than their respective number of Units.
Term, Dissolution and Distributions on Liquidation.We will continue in existence for 50 years unless we are terminated earlier by a final terminating event as described below, or by an event which causes
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the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if an event which causes our dissolution under state law is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will we be liquidated. A final terminating event is any of the following:
| • | the election to terminate us by our managing general partner or the affirmative vote of our participants whose Units equal a majority of our total Units; | ||
| • | our termination under Section 708(b)(1)(A) of the Internal Revenue Code because no part of our business is being carried on; or | ||
| • | we cease to be a going concern. |
On our liquidation a participant will receive his capital interest in us. Generally, this means an undivided interest in our assets, after payments to our creditors, in the ratio the participant’s capital account bears to all of the capital accounts in us until all capital accounts have been reduced to zero. Thereafter, the participant’s capital interest in our remaining assets will equal the participant’s interest in our related revenues.
Any in-kind property distributions to a participant from us must be made to a liquidating trust or similar entity, unless the participant affirmatively consents to receive an in-kind property distribution after being told the risks associated with the direct ownership of our natural gas and oil properties or there are alternative arrangements in place which assure that the participant will not be responsible for the operation or disposition of our natural gas and oil properties. If our managing general partner has not received a participant’s written consent to the in-kind distribution within 30 days after it is mailed, then it will be presumed that the participant did not consent. Our managing general partner may then sell the asset at the best price reasonably obtainable from an independent third-party, or to itself or its affiliates at fair market value as determined by an independent expert selected by our managing general partner. Also, if we are liquidated our managing general partner will be repaid for any debts owed it by us before there are any distributions to our participants.
Transferability.Our Units may not be sold, assigned or otherwise transferred unless certain conditions set forth in our partnership agreement are satisfied, including:
| • | an opinion of counsel acceptable to our managing general partner that the sale, assignment, pledge, hypothecation, or transfer of the Unit does not require registration and qualification under the Securities Act of 1933 and applicable state securities laws; and |
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| • | a determination under the tax laws that a sale, assignment, exchange, or transfer of the Unit would not, in the opinion of our counsel, result in our termination for tax purposes or our being treated as a “publicly-traded” partnership for tax purposes. |
Also, under the partnership agreement transfers are subject to the following limitations:
| • | except as provided by operation of law, we will recognize the transfer of only one or more whole Units unless the participant making the transfer owns less than a whole Unit, in which case the entire fractional interest in the Unit must be transferred; | ||
| • | the costs and expenses associated with the transfer must be paid by the participant transferring the Unit; | ||
| • | the form of transfer must be in a form satisfactory to our managing general partner; and | ||
| • | the terms of the transfer must not contravene those of our partnership agreement. |
A transfer of a participant’s Unit will not relieve the participant of responsibility for any obligations related to his Unit under the partnership agreement. Also, the transfer of a Unit does not grant rights under the partnership agreement, as among the transferees, to more than one party unanimously designated by the transferees to our managing general partner. Further, the transfer of a Unit does not require an accounting by our managing general partner. Any transfer when the assignee of the Unit does not become a substituted partner, as described below, will be effective as of midnight of the last day of the calendar month in which it is made or, at our managing general partner’s election, 7:00 A.M. of the following day.
Finally, a sale of a participant’s Units could create adverse tax and economic consequences for the participant. The sale or exchange of Units held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions by the participant for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain, regardless of how long the participant owned the Units. If the Units are held for 12 months or less, then the gain or loss generally will be short-term gain or loss. The participant’s pro rata share of our liabilities, if any, as of the date of the sale or exchange must be included in the amount realized by the participant. Thus, the gain recognized by the participant may result in a tax liability greater than the cash proceeds, if any, received by the participant from the sale or other taxable disposition of his Units.
Under our partnership agreement, an assignee (transferee) of a Unit may become a substituted partner only on meeting certain further conditions. The conditions to become a substituted partner are as follows:
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| • | the assignor (transferor) gives the assignee the right; | ||
| • | our managing general partner consents to the substitution; | ||
| • | the assignee pays all costs and expenses incurred in connection with the substitution; and | ||
| • | the assignee executes and delivers, in a form acceptable to our managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his or her agreement to be bound by all terms and provisions of the partnership agreement. |
A substituted partner is entitled to all of the rights of full ownership of the assigned Units, including the right to vote. We will amend our records at least once each calendar quarter to effect the substitution of substituted partners.
Presentment Feature.Beginning in 2011 a participant may present his Units to our managing general partner for purchase. However, a participant is not required to offer his Units to our managing general partner, and may receive a greater return if the Units are retained.
Our managing general partner has no obligation to establish a reserve to satisfy the presentment obligation, and it does not intend to do so. Our managing general partner may immediately suspend its purchase obligation by notice to our participants if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange financing or other consideration for this purpose on terms it deems reasonable.
Our managing general partner will not purchase less than one Unit unless the fractional Unit represents the participant’s entire interest in us, nor more than 5% of our total Units in any calendar year. If fewer than all of the Units presented at any time are to be purchased, then the Units to be purchased will be selected by lot. Our managing general partner may not waive the limit on its purchasing more than 5% of our total Units in any calendar year.
Our managing general partner’s obligation to purchase the Units presented by our participants may be discharged for its benefit by a third-party or an affiliate of our managing general partner. The Unit will be transferred to the party who pays for it, along with the delivery of an executed assignment. The presentment must be within 120 days of our reserve report discussed below and, in accordance with Treas. Reg. §1.7704-1(f), the purchase may not be made by our managing general partner until at least 60 calendar days after written notice of the participant’s intent to present the Unit was made.
The amount of the presentment price attributable to our natural gas and oil reserves will be determined based on our last reserve report. Beginning in 2008, and every year thereafter, our managing general partner will prepare
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an annual reserve report of our natural gas and oil proved reserves which will be reviewed by an independent expert.
The presentment will not be considered effective until the following conditions are satisfied:
| • | the participant receives information concerning the present worth of our future net revenues attributable to our proved reserves; | ||
| • | the participant agrees to the presentment price as calculated below; and | ||
| • | payment has been made in cash or other consideration as agreed to between our managing general partner and the participant. |
The presentment price to a participant will be based on his share of our net assets and liabilities as described below, based on the ratio that his number of Units bears to the total number of our Units. The presentment price will include the sum of the following partnership items:
| • | an amount based on 70% of the present worth of future net revenues from our proved reserves determined as described above; | ||
| • | cash on hand; | ||
| • | prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and | ||
| • | the estimated market value of all assets not separately specified above, determined in accordance with standard industry valuation procedures. |
There will be deducted from the foregoing sum the following partnership items:
| • | an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and | ||
| • | any distributions made to the participant between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, natural gas, or a producing property, for purposes of determining the reduction of the presentment price the distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of our proved reserves. |
The amount may be further adjusted by our managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price because of the various considerations described in our partnership agreement.
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Voting Rights and Amendments.Other than as set forth below, a participant generally will not be entitled to vote on any of our partnership matters at any meeting. However, at any time participants whose Units equal 10% or more of our total Units may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of our managing general partner. On the matters being voted on a participant is entitled to one vote per Unit or, if the participant owns a fractional Unit, that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of our total Units may vote to:
| • | dissolve us; | ||
| • | remove our managing general partner and elect a new managing general partner; | ||
| • | elect a new managing general partner if our managing general partner elects to withdraw from the partnership; | ||
| • | remove the operator and elect a new operator; | ||
| • | approve or disapprove the sale of all or substantially all of our assets; | ||
| • | cancel any contract for services with our managing general partner, the operator, or their affiliates, which is not otherwise described in the private placement memorandum for the offering of our Units or our partnership agreement without penalty on 60 days notice; and | ||
| • | amend our partnership agreement; provided however, any amendment may not: |
| • | without the approval of our participants or our managing general partner, increase the duties or liabilities of the participants or our managing general partner or increase or decrease the profits or losses or required capital contribution of our participants or our managing general partner; or | ||
| • | without the unanimous approval of our participants, affect the classification of our income and loss for federal income tax purposes. |
Although our managing general partner and its officers, directors, and affiliates could have voted on certain issues as a participant if they had purchased Units, they did not purchase any Units. In addition to amendments by our participants as described above, amendments to our partnership agreement may be proposed in writing by our managing general partner and adopted with the consent of participants whose Units equal a majority of our total Units. Our partnership agreement may also be amended by our managing general partner without the consent of our participants for certain limited purposes set forth in our partnership agreement.
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Books and Records.Our managing general partner is required to keep true and accurate books of account of all of our financial activities in accordance with generally accepted accounting principles. A participant may inspect and copy any of the records, including a list of our participants subject to the conditions described below, at any reasonable time after giving adequate notice to our managing general partner. Access to the list of our participants is subject to the following conditions:
| • | an alphabetical list of the names, addresses, and business telephone numbers of our participants along with the number of Units held by each of them (the “Participant List”) must be maintained as a part of our books and records and be available for inspection by any participant or his designated agent at our home office on the participant’s request; | ||
| • | the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List; | ||
| • | a copy of the Participant List must be mailed to any participant requesting the Participant List within 10 days of the written request; | ||
| • | the purposes for which a participant may request a copy of the Participant List include, without limitation, matters relating to the participant’s voting rights under our partnership agreement and the exercise of participant’s rights under the federal proxy laws; and | ||
| • | our managing general partner may refuse to exhibit, produce, or mail a copy of the Participant List as requested if our managing general partner believes that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a participant relative to our affairs. Our managing general partner will require the participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the participant’s interest in us. |
Also, our managing general partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time.
Restrictions on Roll-Up Transactions.In connection with any proposed transaction which is considered a “Roll-up Transaction” involving us and the issuance of securities of an entity (a “Roll-up Entity”) that would be created or would survive after the successful completion of the Roll-up Transaction, an appraisal of all of our natural gas and oil properties must be obtained from a competent independent appraiser. Our properties must be appraised on a consistent basis, and the appraisal must be based on the evaluation of all relevant information and
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must indicate the value of our properties as of a date immediately before the announcement of the proposed Roll-up Transaction. The appraisal must assume an orderly liquidation of our properties over a 12-month period. The terms of the engagement of the independent appraiser must clearly state that the engagement is for the benefit of us and our participants. A summary of the appraisal, indicating all of the material assumptions underlying the appraisal, must be included in a report to our participants in connection with the proposed Roll-up Transaction. A “Roll-up Transaction” is transaction involving our acquisition, merger, conversion or consolidation, directly or indirectly, and the issuance of securities of a Roll-up Entity. This term does not include:
| • | a transaction involving our securities that have been listed on a national securities exchange or included for quotation on Nasdaq National Market System for at least 12 months; or | ||
| • | a transaction involving only our conversion to corporate, trust, or association form if, as a consequence of the transaction, there will be no significant adverse change in any of the following: voting rights; the term of our existence; compensation to our managing general partner; or our investment objectives. |
In connection with a proposed Roll-up Transaction, the person sponsoring the Roll-up Transaction must offer to our participants who vote “no” on the proposal the choice of:
| • | accepting the securities of the Roll-up Entity offered in the proposed Roll-up Transaction; or |
| • | one of the following: |
| • | remaining as participants in us and preserving their interests in us on the same terms and conditions as existed previously, or | ||
| • | receiving cash in an amount equal to each participant’s pro rata share of the appraised value of our net assets. |
We are prohibited from participating in any proposed Roll-Up Transaction:
| • | which would result in the diminishment of any participant’s voting rights under the Roll-up Entity’s chartering agreement; | ||
| • | in which the democracy rights of our participants in the Roll-up Entity would be less than those provided for under §§4.03(c)(1) and 4.03(c)(2) of our partnership agreement or, if the Roll-up Entity is a corporation, then the democracy rights of our participants must correspond to the |
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| democracy rights provided for our participants in our partnership agreement to the greatest extent possible; | |||
| • | which includes provisions that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-up Entity; | ||
| • | in which our participants’ rights of access to the records of the Roll-up Entity would be less than those provided for under §§4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of our partnership agreement; | ||
| • | in which any of the costs of the transaction would be borne by us if our participants whose Units equal a majority of our total Units do not vote to approve the proposed Roll-Up Transaction; and | ||
| • | unless the Roll-up Transaction is approved by our participants whose Units equal a majority of our total Units. |
We currently have no plans to enter into a Roll-Up Transaction.
Withdrawal of Managing General Partner.After 10 years our managing general partner may voluntarily withdraw as our managing general partner for whatever reason by giving 120 days’ written notice to our participants. Although our withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of our participants whose Units equal a majority of our total Units. If our participants, however, choose to terminate our existence and do not select a substitute managing general partner, then we would terminate and dissolve which could result in adverse tax and other consequences to our participants.
Also, our managing general partner may assign its general partner interest in us to its affiliates and it may withdraw a property interest from us in the form of a working interest in our wells equal to or less than its revenue interest in us without the consent of our participants.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Under the terms of our partnership agreement, our managing general partner, the operator, and their affiliates have limited their liability to us and our participants for any loss suffered by us or the participants which arises out of any action or inaction on their part if:
| • | they determined in good faith that the course of conduct was in our best interest; |
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| • | they were acting on our behalf or performing services for us; and | ||
| • | their course of conduct did not constitute negligence or misconduct. |
In addition, our partnership agreement provides for our indemnification of our managing general partner, the operator, and their affiliates against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in our partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, in the SEC’s opinion this indemnification is contrary to public policy and therefore unenforceable.
Payments arising from the indemnification or agreement to hold harmless described above are recoverable only out of our tangible net assets, including our revenues, and any insurance proceeds. Still, the use of our funds or assets for indemnification of our managing general partner, the operator or an affiliate would reduce amounts available for our operations or for distribution to our participants.
Under our partnership agreement, we are not allowed to pay the cost of the portion of any insurance that insures our managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified as described above. However, our funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if we have adequate funds available and certain conditions in our partnership agreement are met.
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to Financial Statements
| Page | ||
| Report of Independent Registered Public Accounting Firm | 65 | |
| Balance Sheet | 66 | |
| Statement of Operations | 67 | |
| Statement of Partners’ Capital Accounts | 68 | |
| Statement of Cash Flows | 69 | |
| Notes to Financial Statements | 70 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas America Series 27-2006 L.P.
Atlas America Series 27-2006 L.P.
We have audited the accompanying balance sheet of Atlas America Series 27-2006 L.P. (a Delaware Limited Partnership) as of December 31, 2006, and the related statement of operations, changes in partners’ capital, and cash flows for the period July 21, 2006 (date of formation) through December 31, 2006. 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 America Series 27-2006 L.P. as of December 31, 2006 and the results of its operations and its cash flows for the period July 21, 2006 (date of formation) through December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
April 20, 2007
April 20, 2007
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ATLAS AMERICA SERIES 27-2006 L.P.
BALANCE SHEET
DECEMBER 31,
BALANCE SHEET
DECEMBER 31,
| 2006 | ||||
ASSETS: | ||||
| Current assets: | ||||
| Cash and cash equivalents | $ | 100 | ||
| Accounts receivable-affiliate | 65,345,700 | |||
| Total current assets | 65,345,800 | |||
| Oil and gas properties, net | 7,127,300 | |||
| $ | 72,473,100 | |||
LIABILITIES AND PARTNERS’ CAPITAL | ||||
| Current liabilities: | ||||
| Accrued liabilities | $ | 12,000 | ||
| Total current liabilities | 12,000 | |||
| Asset retirement obligation | 333,400 | |||
| Partners’ capital: | ||||
| Managing general partner | 1,246,200 | |||
| Investor partners (2,840 units) | 70,881,500 | |||
| 72,127,700 | ||||
| $ | 72,473,100 | |||
The accompanying notes are an integral part of these financial statements
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ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENT OF OPERATIONS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
STATEMENT OF OPERATIONS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
REVENUES | ||||
| Natural gas and oil | $ | 17,500 | ||
| Total revenues | 17,500 | |||
COST AND EXPENSES | ||||
| Production | 2,100 | |||
| Depletion | 4,000 | |||
| General and administrative | 12,100 | |||
| Total expenses | 18,200 | |||
Net loss | $ | (700 | ) | |
Allocation of net loss: | ||||
| Managing general partner | $ | 800 | ||
| Investor partners | $ | (1,500 | ) | |
| Net loss per investor partnership unit | $ | (1 | ) | |
The accompanying notes are an integral part of these financial statements
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ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENT OF PARTNERS’ CAPITAL ACCOUNTS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
STATEMENT OF PARTNERS’ CAPITAL ACCOUNTS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
| Managing | ||||||||||||
| General | Investor | |||||||||||
| Partner | Partners | Total | ||||||||||
Balance at July 21, 2006 | $ | — | $ | — | $ | — | ||||||
| Partners’ capital contributions | ||||||||||||
| Cash | 100 | 70,883,000 | 70,883,100 | |||||||||
| Syndication and offering costs | 8,506,000 | — | 8,506,000 | |||||||||
| Tangible equipment/leasehold costs | 1,245,300 | — | 1,245,300 | |||||||||
| Total contributions | 9,751,400 | 70,883,000 | 80,634,400 | |||||||||
| Syndication and offering costs, immediately charged to capital | (8,506,000 | ) | — | (8,506,000 | ) | |||||||
| 1,245,400 | 70,883,000 | 72,128,400 | ||||||||||
| Participation in revenue and costs and expenses | ||||||||||||
| Net production revenues | 5,000 | 10,400 | 15,400 | |||||||||
| Depletion | (300 | ) | (3,700 | ) | (4,000 | ) | ||||||
| General and administrative | (3,900 | ) | (8,200 | ) | (12,100 | ) | ||||||
| Net loss | 800 | (1,500 | ) | (700 | ) | |||||||
Balance at December 31, 2006 | $ | 1,246,200 | $ | 70,881,500 | $ | 72,127,700 | ||||||
The accompanying notes are an integral part of these financial statements
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ATLAS AMERICA SERIES 27-2006 L.P.
STATEMENT OF CASH FLOWS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
STATEMENT OF CASH FLOWS
FOR THE PERIOD JULY 21, 2006 (date of formation) THROUGH DECEMBER 31, 2006
Cash flows from operating activities: | ||||
| Net loss | $ | (700 | ) | |
| Adjustments to reconcile net loss to net cash provided by operating activities: | ||||
| Depletion | 4,000 | |||
| Increase in accrued liabilities | 12,000 | |||
| Increase in accounts receivable affiliate | (15,300 | ) | ||
| Net cash provided by operating activities | — | |||
Cash flows from investing activities: | ||||
| Oil and gas well drilling contracts paid to managing general partner | (70,883,000 | ) | ||
| Net cash used in investing activities | (70,883,000 | ) | ||
Cash flows from financing activities: | ||||
| Partners’ capital contributions | 70,883,100 | |||
| Net cash provided by financing activities | 70,883,100 | |||
| Net increase in cash and cash equivalents | 100 | |||
| Cash and cash equivalents at beginning of period | — | |||
| Cash and cash equivalents at end of period | $ | 100 | ||
Supplemental Schedule of non-cash investing and financing activities: | ||||
| Managing general partner adjusted asset contributions: | ||||
| Tangible equipment costs, included in oil and gas properties | $ | 895,200 | ||
| Lease costs included in oil and gas properties | 350,100 | |||
| Syndication and offering costs | 8,506,000 | |||
| $ | 9,751,300 | |||
| Asset retirement obligation | $ | 333,400 | ||
The accompanying notes are an integral part of these financial statements
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ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2006
NOTE 1 – DESCRIPTION OF BUSINESS
Atlas America Series 27-2006 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 1,359 subscribers to units as either Limited Partners or Investor General Partners depending upon their election. As of December 31, 2006, there were 1,359 investors who contributed $70,883,000. The Partnership was formed on July 21, 2006 to drill and operate gas wells located in Pennsylvania and Tennessee. At December 31, 2006, the Partnership’s properties were in the process of drilling. Recoverability of the cost of properties is dependent on the results of such development activities.
NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of significant accounting policies applied in the preparation of the accompanying financial statements follows:
Basis of Accounting
The financial statements are prepared in accordance with accounting principles generally accepted in the United States of America.
Use of Estimates
Preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues, costs and expenses during the reporting period. Actual results could differ from these estimates.
Receivables
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of credit information. Credit is extended on an unsecured basis to many of its energy purchasers. At December 31, 2006, the MGP’s credit evaluation indicated that the Partnership has no need for an allowance for possible losses.
Revenue Recognition
Revenues from sales of natural gas and oil are recognized by the Partnership when the gas and oil have been delivered to the purchaser. The Partnership’s natural gas and oil is sold under various contracts entered into by its MGP. Virtually all of the MGP’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price the Partnership receives from the sale of its natural gas fluctuates to remain competitive with natural gas supplies generally available in the market.
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 $15,800 at December 31, 2006, which are included Accounts receivable – affiliate on the Partnership’s balance sheet.
70
ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Fair Value of Financial Instruments
For cash, receivables and payables, the carrying amounts 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, 2006.
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, 2006, the Partnership had no deposits over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.
Property and Equipment
Property and equipment are stated at cost. Depletion is based on cost less estimated salvage value primarily using the unit-of-production method over the assets’ estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized. Oil and gas properties consist of the following at the date indicated:
| At December 31, | ||||
| 2006 | ||||
| Mineral interest in properties: | ||||
| Proved properties | $ | 350,100 | ||
| Wells and related equipment | 6,781,200 | |||
| 7,131,300 | ||||
| Accumulated depletion of oil and gas properties | (4,000 | ) | ||
| $ | 7,127,300 | |||
Oil and Gas Properties
The Partnership uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip wells are capitalized. Oil is converted to gas equivalent basis (“mcfe”) at the rate of one barrel equals 6 mcf.
71
ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Properties (Continued)
The Partnership’s long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and asset retirement obligation 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 estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. The fair market value is the present value of future net revenues discounted at 10%, using a 12 month NYMEX forward looking strip price for natural gas. There was no impairment charge for the period ended December 31, 2006.
Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest where the property had been assessed for impairment, a gain or loss is recognized in the statements of operations.
Asset Retirement Obligation
The fair values of asset retirement obligations are recognized in the period they are incurred if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing properties and include costs to dismantle and relocate or dispose of production equipment, gathering systems, wells and related structures. Estimates are based on 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 Partnership does not provide for a market risk premium associated with asset retirement obligation because a reliable estimate cannot be determined, see Note 3.
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.
The Partnership accounts for environmental contingencies in accordance with SFAS No. 5Accounting for Contingencies. 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 Resources, LLC maintains insurance that may cover in whole or in part certain environmental expenditures. For the period ended December 31, 2006, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability.
Major Customers
Our natural gas and oil is sold under contract to various purchasers. For the period ended December 31, 2006, sales to UGI Energy Services, Inc., Dominion Field Services, Inc. and Colonial Energy, Inc. accounted for 61%, 22% and 17%, respectively, of total revenues. No other customer accounted for more than 10% of our total revenues for the period ended December 31, 2006. As of December 31, 2006, however, only six of the total 229.76 net wells we expect to drill and complete were online and producing natural gas. Thus, our percentages of sales to the customers set forth above should not be considered representative of our sales and customers after all of our wells are online and producing.
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 his pro rata share of all items of partnership income and deductions in computing his federal income tax liability.
72
ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Issued Financial Accounting Standards
In February 2007, the Financial Accounting Standards Board, (“FASB”) issued Statement of Financial Accounting Standards No. 159,The Fair Value Option for Financial Assets and Financial Liabilities, (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement will be effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. The Statement offers various options in electing to apply the provisions of this statement and at this time, the Partnership has not made any decisions on its application to its financial position or results of operations, and is currently evaluating the impact of the adoption of SFAS 159 on its financial position and results of operations.
In June 2006, the FASB issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes and Interpretation of FASB Statement No 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for us beginning January 1, 2007. The Partnership is a non-taxable entity and its taxable income or loss will be absorbed by the Partners. The Partnership is currently evaluating the impact of the adoption of FIN 48 on its financial position and results of operations, but does not currently expect the adoption of FIN 48 to have a material impact on its financial position or results of operations.
NOTE 3 – ASSET RETIREMENT OBLIGATION
The Partnership accounts for its estimated plugging and abandonment costs for its oil and gas properties in accordance with SFAS 143,Accounting for Asset Retirement Obligationand FASB Interpretation No. 47Accounting for Conditional Asset Retirement Obligation.
A reconciliation of the Partnership’s liability for plugging and abandonment costs for the period ended December 31, 2006 is as follows:
| 2006 | ||||
| Asset retirement obligation, at beginning of period | $ | — | ||
| Liabilities incurred from drilling wells | 333,400 | |||
| Asset retirement obligation, at end of period | $ | 333,400 | ||
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ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 4 — PARTICIPATION IN REVENUES AND COSTS
The MGP and the other partners 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) | 32.6 | % | 67.4 | % | ||||
| Operating costs, administrative costs, direct costs and all other operating costs(2) | 32.6 | % | 67.4 | % | ||||
| Intangible drilling costs | 0 | % | 100 | % | ||||
| Tangible equipment costs | 70 | % | 30 | % | ||||
| (1) | Subject to the MGP’s subordination obligation, substantially all partnership revenues are shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP receives an additional 7% of the partnership revenues, which may not exceed 40%. | |
| (2) | These costs are 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. Investor general partner units can be converted into 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 5 – 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:
| • | Drilling contracts to drill and complete wells for the Partnership are charged at cost plus 15%. The cost of the wells includes reimbursement to Atlas of its general and administrative overhead cost ($15,000 per well) and all ordinary and actual costs of drilling, testing and completing the wells. The Partnership paid $70,883,000 to its MGP in 2006 under the drilling contract, of which $5,552,600 was used for drilling costs and the remaining $65,330,400 was included in accounts-receivable affiliate in the Partnership’s Balance Sheet. | ||
| • | The Partnership’s MGP contributed undeveloped leases necessary to cover each of the Partnership’s prospects and as of December 31, 2006 received a credit to its capital account in the Partnership of $350,100. | ||
| • | 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 fees will be charged when the well is producing for the majority of the month. Administrative costs incurred in 2006 were $100. | ||
| • | Monthly well supervision fees which are included in production expenses in the Partnership’s Statement of Operations are payable at $362 per well per month for operating and maintaining the wells. Well supervision fees will be charged when the well is producing for the majority of the month. Well supervision fees incurred in 2006 were $400. | ||
| • | Transportation fees which are included in production expenses in the Partnership’s Statement of Operations are payable at rates ranging from $.29-$.35 per (one thousand cubic feet), (“Mcf”) to 10% of the natural gas sales price. A gathering fee is paid to the MGP at a competitive rate for each Mcf of natural gas transported. Transportation fees incurred in 2006 were $1,800. |
74
ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 5 – CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (Continued)
| • | The managing general partner and its affiliates are reimbursed for all direct costs expended on the Partnership’s behalf. For the period ended December 31, 2006, the managing general partner was reimbursed $11,900 for direct costs. | ||
| • | Asset contributions from the managing general partner which are reported in the Partnership’s Statement of Cash Flows as a non-cash investing activity for the period ended December 31, 2006 were $9,751,300. | ||
| • | The MGP received a credit to it’s capital account of $8,506,000 in 2006 for fees, commissions and reimbursement costs to organize the Partnership. |
The MGP performs 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.
NOTE 6 — COMMITMENTS
Subject to certain conditions, investor partners may present their interests beginning in 2011 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 and in the event that the MGP is unable to obtain the necessary funds, it may suspend its purchase obligation.
Beginning one year after each of the Partnership’s wells has been placed into production, the MGP, as operator, may retain $200 per month per well to cover estimated future plugging and abandonment costs. As of December 31, 2006, the MGP has not withheld any such funds.
NOTE 7 — SUBORDINATION OF MANAGING GENERAL PARTNER’S REVENUE SHARE
Under the terms of the partnership agreement, the MGP may be required to subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, administrative costs and well supervision fees to the receipt by the investor partners of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of revenues to its investor partners.
NOTE 8 — INDEMNIFICATION
In order to limit the potential liability of any investor general partners, the MGP has agreed to indemnify each investor that elects to be a general partner from any liability incurred which exceeds such partner’s share of Partnership assets.
NOTE 9 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
The supplementary information summarized below presents the results of natural gas and oil activities in accordance with Statements of Financial Accounting Standards No. 69,Disclosures About Oil and Gas Producing Activities,(“SFAS No. 69”). Annually, reserve value information is provided to the investor partners pursuant to the partnership agreement. The partnership agreement provides a presentment feature whereby the MGP will buy partnership units, subject to annual limitations, based upon a valuation formula price in the partnership agreement.
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ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 9 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
No consideration has been given in the following information to the income tax effect of the activities, as the Partnership is not treated as a taxable entity for income tax purposes.
| (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 December 31:
| 2006 | ||||
| Mineral interest in properties – proved properties | $ | 350,100 | ||
| Wells and related equipment | 6,781,200 | |||
| Accumulated depletion | (4,000 | ) | ||
Net capitalized cost | $ | 7,127,300 | ||
| (2) | Results of Operations of Oil and Gas Producing Activities |
The following table presents the results of operations related to natural gas and oil production for the period ended December 31:
| 2006 | ||||
| Natural gas and oil sales | $ | 17,500 | ||
| Production costs | (2,100 | ) | ||
| Depletion | (4,000 | ) | ||
| General and administrative expenses | (12,100 | ) | ||
Results of operations from oil and gas producing activities | $ | (700 | ) | |
| (3) | Costs incurred in Oil and Gas Producing Activities |
Costs incurred for the period ended December 31, are as follows:
| 2006 | ||||
| Acquisition costs | $ | 350,100 | ||
| Tangible equipment and drilling costs | 895,200 | |||
Total costs incurred | $ | 1,245,300 | ||
(4)Oil and Gas Reserve Information
The information presented below represents estimates of proved natural gas and oil reserves. The estimates of the Partnership’s proved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum-engineering firm, as of December 31, 2006. All reserves are located within the United States of America. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual arrangements. Proved reserves are estimated quantities of crude oil and natural gas 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.
76
ATLAS AMERICA SERIES 27-2006 L.P.
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTES TO FINANCIAL STATEMENTS – (Continued)
DECEMBER 31, 2006
NOTE 9 — NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
Proved developed reserves are generally those which are expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. All reserves are proved developed reserves and are located in the Appalachian Basin area.
There are numerous uncertainties inherent in estimating quantities of proved 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 which effects have not been provided.
| Natural Gas | Oil | |||||||
| (Mcf) | (Bbls) | |||||||
| Proved developed reserves: | ||||||||
| Beginning of period | — | — | ||||||
| Proved developed reserves | 2,843,800 | 2,300 | ||||||
| Production | (2,000 | ) | — | |||||
Balance December 31, 2006 | 2,841,800 | 2,300 | ||||||
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| ITEM 14. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. |
None.
| ITEM 15. | FINANCIAL STATEMENTS AND EXHIBITS |
(a) The following documents are filed as part of this Form 10:
| 1. | Financial Statements | ||
| The financial statements of Atlas America Series 27-2006 L.P. as of December 31, 2006 are set forth in Item 13 “Financial Statements and Supplementary Data.” | |||
| 2. | Exhibits |
| Exhibit No. | Description | |||||
| 4.1 | Certificate of Limited Partnership for Atlas America Series 27-2006 L.P. | |||||
| 4.2 | Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P. | |||||
| 10.1 | Drilling and Operating Agreement for Atlas America Series 27-2006 L.P. | |||||
| 10.2 | Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. | |||||
| 10.3 | Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. | |||||
| 10.4 | Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation | |||||
| 10.5 | Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. | |||||
| 10.6 | Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble Corporation, and Resource Energy Inc., and Viking Resources Corporation | |||||
| 10.7 | Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. | |||||
| 10.8 | First Amendment to Base Contract for Sale and Purchase of Natural Gas | |||||
78
| Exhibit No. | Description | |||||
| 10.9 | Second Amendment to Base Contract for Sale and Purchase of Natural Gas | |||||
| 10.10 | Third Amendment to Base Contract for Sale and Purchase of Natural Gas | |||||
| 10.11 | Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. | |||||
| 10.12 | Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. | |||||
| 10.13 | Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas Resources, Inc. et. al. and First Energy Solutions Corp. for the period from April 1, 2006 through March 31, 2007 production/calendar periods | |||||
| 10.14 | Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK | |||||
| 10.15 | Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. | |||||
| 10.16 | Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy, LLC | |||||
| 10.17 | Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., and Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp., and Atlas Resources, Inc. to the Master Natural Gas Gathering Agreement dated February 2, 2000 and the Natural Gas Gathering Agreement dated January 1, 2002 | |||||
| 10.18 | Contribution, Conveyance and Assumption Agreement dated December 18, 2006 among Atlas America, Inc., Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC | |||||
| 10.19 | Omnibus Agreement dated December 18, 2006 between Atlas Energy Resources, LLC and Atlas America, Inc. | |||||
| 10.20 | Management Agreement dated December 18, 2006 among Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc. | |||||
| 10.21 | Amendment and Joiner to Omnibus Agreement dated December 18, 2006, among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC | |||||
| 10.22 | Amendment and Joiner to Gas Gathering Agreement dated December 18, 2006, among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC | |||||
79
| Exhibit No. | Description | |||||
| 10.23 | Revolving Credit Agreement dated as of December 18, 2006 Among Atlas Energy Operating Company, LLC, as Borrower; AER Pipeline Construction, Inc., AIC, LLC, Atlas America, LLC, Atlas Energy Ohio, LLC, Atlas Energy Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, REI-NY, LLC, Resource Energy, LLC, Resource Well Services, LLC, and Viking Resources LLC as Guarantors; Wachovia Bank, National Association as Administrative Agent and Issuing Bank; Bank Of America, N.A. and Compass Bank as Co-Syndication Agents; Bank Of Oklahoma, N.A., U.S. Bank, National Association and BNP Paribas as Co-Documentation Agents and the Lenders Signatory Hereto $250,000,000 Senior Secured Revolving Credit Facility Wachovia Capital Markets, LLC as Lead Arranger | |||||
| 10.24 | Continuing Guaranty Agreement dated December 18, 2006 by Atlas Energy Resources, LLC in Favor of Wachovia Bank, National Association, as Administrative Agent for the Lenders | |||||
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SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.
| ATLAS AMERICA SERIES 27-2006 L.P. (Registrant) | ||||
| By: | Atlas Resources, LLC | |||
| Managing General Partner | ||||
| Date: April 30, 2007 | By: | /s/ Freddie Kotek | ||
| Freddie Kotek, Chairman of the Board of Directors, | ||||
| Chief Executive Officer and President | ||||
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EXHIBIT INDEX
| Exhibit No. | Description | |
| 4.1 | Certificate of Limited Partnership for Atlas America Series 27-2006 L.P. | |
| 4.2 | Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 27-2006 L.P. | |
| 10.1 | Drilling and Operating Agreement for Atlas America Series 27-2006 L.P. | |
| 10.2 | Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. | |
| 10.3 | Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. | |
| 10.4 | Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation | |
| 10.5 | Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. | |
| 10.6 | Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble Corporation, and Resource Energy Inc., and Viking Resources Corporation | |
| 10.7 | Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. | |
| 10.8 | First Amendment to Base Contract for Sale and Purchase of Natural Gas | |
| 10.9 | Second Amendment to Base Contract for Sale and Purchase of Natural Gas | |
| 10.10 | Third Amendment to Base Contract for Sale and Purchase of Natural Gas | |
| 10.11 | Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. | |
| 10.12 | Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. | |
| 10.13 | Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas Resources, Inc. et. al. and First Energy Solutions Corp. for the period from April 1, 2006 through March 31, 2007 production/calendar periods | |
| 10.14 | Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK | |
| 10.15 | Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. | |
| 10.16 | Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy, LLC |
82
| Exhibit No. | Description | |
| 10.17 | Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., and Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp., and Atlas Resources, Inc. to the Master Natural Gas Gathering Agreement dated February 2, 2000 and the Natural Gas Gathering Agreement dated January 1, 2002 | |
| 10.18 | Contribution, Conveyance and Assumption Agreement dated December 18, 2006 among Atlas America, Inc., Atlas Energy Resources, LLC, and Atlas Energy Operating Company, LLC | |
| 10.19 | Omnibus Agreement dated December 18, 2006 between Atlas Energy Resources, LLC and Atlas America, Inc. | |
| 10.20 | Management Agreement dated December 18, 2006 among Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc. | |
| 10.21 | Amendment and Joiner to Omnibus Agreement dated December 18, 2006, among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource energy, LLC, Viking Resources, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC | |
| 10.22 | Amendment and Joiner to Gas Gathering Agreement dated December 18, 2006, among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, Atlas America, LLC, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC | |
| 10.23 | Revolving Credit Agreement dated as of December 18, 2006 Among Atlas Energy Operating Company, LLC, as Borrower; AER Pipeline Construction, Inc., AIC, LLC, Atlas America, LLC, Atlas Energy Ohio, LLC, Atlas Energy Resources, LLC, Atlas Noble, LLC, Atlas Resources, LLC, REI-NY, LLC, Resource Energy, LLC, Resource Well Services, LLC, and Viking Resources LLC as Guarantors; Wachovia Bank, National Association as Administrative Agent and Issuing Bank; Bank Of America, N.A. and Compass Bank as Co-Syndication Agents; Bank Of Oklahoma, N.A., U.S. Bank, National Association and BNP Paribas as Co-Documentation Agents and the Lenders Signatory Hereto $250,000,000 Senior Secured Revolving Credit Facility Wachovia Capital Markets, LLC as Lead Arranger | |
| 10.24 | Continuing Guaranty Agreement dated December 18, 2006 by Atlas Energy Resources, LLC in Favor of Wachovia Bank, National Association, as Administrative Agent for the Lenders |
83