Table 5 sets forth payments made to the managing general partners and its affiliates from its previous partnerships.
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MANAGEMENT
Managing General Partner and Operator
The partnerships will 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, will serve as the managing general partner of each partnership. However, see “– Transactions with Management and Affiliates,” below, regarding the managing general partner’s dependence on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for facilities, management and administrative functions and financing for capital expenditures. The managing general partner and its affiliates operate more than 5,100 natural gas and oil wells located in the Appalachian Basin in the states of Ohio, Pennsylvania, New York and Tennessee.
In addition, Atlas America (ATLS) transferred to Atlas Energy Resources, LLC (ATN), a newly-formed, wholly-owned 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 6,325,000 of its 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 its 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 $121,730,000 net proceeds of the offering, 30,301,746 of common units, 748,456 Class A units, and the management incentive interests. Atlas Energy Resources, LLC redeemed 948,750 of the common units from Atlas America in connection with the exercise of the underwriters’ over-allotment option on December 18, 2006. 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 will indemnify Atlas Energy Resources, LLC until December 18, 2007 against certain potential environmental liabilities associated with the operation of the assets and occurring before December 18, 2006 and against claims for covered environmental liabilities made before December 18, 2010. 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 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 the partnerships or the 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; Atlas Energy Resources, LLC will pay Atlas America the gathering fees it receives from the partnerships and the managing general partner’s other partnership and fees associated with production to its interest.
Atlas America retained approximately 83% 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. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any such securities.
Additionally, 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. |
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| • | 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.
Since 1985 the managing general partner has sponsored 16 public and 38 private partnerships to conduct natural gas drilling and development activities in Pennsylvania, Ohio, New York and Tennessee. In these partnerships the managing general partner and its affiliates acted as the operator and the general drilling contractor and were responsible for drilling, completing, and operating the wells. Atlas Resources has a 97% completion rate for wells drilled by its development partnerships.
In September 1998, Atlas Energy Group, Inc., the former parent company of the managing general partner, merged into Atlas America, Inc., a Delaware holding company, which was a subsidiary of Resource America, Inc., a publicly-traded company, which is sometimes referred to in this prospectus as Resource America. In May 2004 Resource America conducted a public offering of a portion of its 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 the managing general partner and Atlas America set forth in “– Officers, Directors and Other Key Personnel,” 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. As a result of the spin-off, Resource America no longer determines the outcome of corporate actions requiring the approval of Atlas America’s stockholders, such as the election and removal of directors, mergers or other business combinations involving Atlas America, future issuances of Atlas America’s common stock or other securities and amendments to Atlas America’s certificate of incorporation and bylaws. 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 the managing general partner’s primary office.
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Officers, Directors and Other Key Personnel of Managing General Partner
The officers and directors of the managing general partner will serve until their successors are elected. The officers, directors, and key personnel of the 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 |
Nancy J. McGurk | | 50 | | Senior Vice President, Chief Financial Officer 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 |
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 the 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 will devote approximately 95% of his professional time to the business and affairs of the 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 the 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 the 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 the managing general partner. Mr. Carolas is a certified petroleum geologist and has been with the 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 the managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Jeffrey C. Simmons. Executive Vice President – Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy Management, Inc. since 2006. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the 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 the 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 the managing general partner’s other affiliates, primarily Viking Resources and Resource Energy.
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Jack L. Hollander. Senior Vice President – Direct Participation Programs since January 2002 and before that he served as Vice President – Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President – Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar and the Chairman of the Investment Program Association, which is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Nancy J. McGurk. Senior Vice President since January 2002, Chief Financial Officer 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 will devote approximately 80% of her professional time to the business and affairs of the 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 the 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 will devote approximately 5% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner’s other affiliates, 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 the 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 the 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 the 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 the 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 the 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 the 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 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 the 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 the 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 the 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 the 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.
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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 the 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 the 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 the 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 the managing general partner, Atlas America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Organizational Diagram and Security Ownership of Beneficial Owners
Atlas America owns approximately 83% of the limited liability company interests of Atlas Energy Resources, LLC, which owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited liability company interests of the managing general partner. The officers and directors of Atlas America and Atlas Energy Resources, LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The biographies of Messrs. Staines and Simmons are set forth above.
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ORGANIZATIONAL DIAGRAM (1)
(1) | The organizational diagram does not include all of the subsidiaries of Atlas America, Inc. |
(2) | These companies are also engaged in the oil and gas business. Many of the officers and directors of the managing general partner serve as officers and directors of those entities. |
(3) | 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). |
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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 | | 47 | | Executive Vice President |
Michael L. Staines | | 57 | | Executive Vice President and Secretary |
Matthew A. Jones | | 44 | | 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,” above, for biographical information on certain of these individuals who are also officers of the managing general partner. Biographical information on the other officers and directors will be provided by the managing general partner on request.
The managing general partner and its affiliates under Atlas America employ more than 205 persons.
Atlas Energy Resources, 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 | | 44 | | 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,” above, for biographical information on Ms. McGurk, who also is an officer of the 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 the managing general partner on request.
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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 |
Matthew A. Jones | | 44 | | 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,” above, for biographical information on certain of these individuals who are also officers of the managing general partner. Biographical information on the other officers and directors will be provided by the managing general partner on request.
Remuneration of Officers and Directors
No officer or director of the managing general partner will receive any direct remuneration or other compensation from the partnerships. These persons will receive compensation solely from affiliated companies of the managing general partner.
Code of Business Conduct and Ethics
Because the partnerships do not directly employ any persons, the managing general partner has determined that the partnerships 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 the managing general partner, as well as to persons performing services for the managing general partner generally. You may obtain a copy of this Code of Business Conduct and Ethics by a request to the managing general partner at Atlas Resources, LLC, 311 Rouser Road, Moon Township, Pennsylvania 15108.
Transactions with Management and Affiliates
The managing general partner depends on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC, and their affiliates, for management and administrative functions and financing for capital expenditures. The managing general partner paid a management fee to Atlas America for management and administrative services, which amounted to $60 million, $47.5 million and $21.6 million for the years ended September 30, 2006, 2005, and 2004, respectively. Additionally, in connection with the initial public offering of Atlas Energy Resources, LLC described above, Atlas Energy Resources, LLC, Atlas Energy Operating Company, LLC and Atlas Energy Management, Inc. (“Atlas Management”) entered into a management agreement. The management agreement provides that Atlas Management will manage Atlas Energy Resources, LLC’s business affairs under the supervision of Atlas Energy Resources, LLC’s board of directors (the “board”). Atlas Management will provide Atlas Energy Resources, LLC, including the 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; |
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| • | 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; |
| • | 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, including the managing general partner and its partnerships. 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 and losses arising from acts of Atlas Management or its affiliates 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.
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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.
(See “Financial Information Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.,” including the indebtedness owed by the managing general partner to Atlas America.)
The managing general partner and its officers, directors and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by the managing general partner. They may also subscribe for units in the partnerships as described in “Plan of Distribution.”
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION, RESULTS OF OPERATIONS,
LIQUIDITY AND CAPITAL RESOURCES
Both of the partnerships have been formed as limited partnerships under the Delaware Revised Uniform Limited Partnership Act. The partnerships, however, have not included any historical information in this prospectus since they have no net worth, do not own any properties on which wells will be drilled, have no third-party investors, and have not conducted any operations. (See “Capitalization and Source of Funds and Use of Proceeds,” “Proposed Activities,” “Competition, Markets and Regulation,” and “Financial Information Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.”)
Each partnership will depend on the proceeds of this offering and the managing general partner’s capital contributions to carry out its proposed activities. Each partnership intends to use its subscription proceeds to pay the following:
| • | the intangible drilling costs of the partnership’s wells; |
| • | the investors’ share of equipment costs of the partnership’s wells; and |
| • | the investors’ share of any cost overruns of drilling and completing the partnership’s wells. |
The managing general partner believes that each partnership’s liquidity requirements will be satisfied from the following:
| • | subscription proceeds of this offering; |
| • | the managing general partner’s capital contributions; |
| • | cash flow from future operations; and |
| • | partnership borrowings, if necessary. |
The managing general partner also anticipates that no additional funds will be required for operating costs before a partnership begins receiving production revenues from its wells.
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Substantially all of the subscription proceeds of you and the other investors in a partnership will be committed or expended after the offering of the partnership closes. If a partnership requires additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by:
| • | subscription proceeds, if available; |
| • | drilling fewer wells, or acquiring a lesser working interest in one or more wells; |
| • | borrowings from the managing general partner or its affiliates; or |
| • | retaining partnership revenues. |
There will be no borrowings from third-parties. The amount that may be borrowed by a partnership from the managing general partner and its affiliates may not at any time exceed 5% of the partnership’s subscription proceeds from you and the other investors and must be without recourse to you and the other investors. The partnership’s repayment of any borrowings would be from partnership production revenues and would reduce or delay your cash distributions.
If the managing general partner loans money to a partnership, which it is not required to do, then:
| • | the interest charged to the partnership must not exceed the managing general partner’s interest cost or the interest that would be charged to the partnership without reference to the managing general partner’s financial abilities or guarantees by unrelated lenders, on comparable loans for the same purpose; and |
| • | the managing general partner may not receive points or other financing charges or fees, although the actual amount of the charges incurred from third-party lenders may be reimbursed to the managing general partner. |
As of December 18, 2006, the managing general partner’s affiliate, Atlas Energy Operating Company, LLC (“Atlas Energy Operating”) entered into a $250 million senior secured credit facility with Wachovia Bank, National Association, as administrative agent, Wachovia Capital Markets LLC, as lead arranger, and other lenders. The credit facility allows Atlas Energy Operating to borrow up to the determined amount of the borrowing base, which will be based upon the loan collateral value assigned to its various natural gas and oil properties. The initial borrowing base is $155 million. The borrowing base will be subject to redetermination on March 14, 2007 and on a semi-annual basis thereafter. The credit facility will mature on December 18, 2011.
Atlas Energy Operating’s obligations under the credit facility are secured by mortgages on its natural gas and oil properties as well as a pledge of all of its ownership interests in its operating subsidiaries including the managing general partner, other than Anthem Securities. Atlas Energy Operating will be required to maintain the mortgages on properties representing at least 80% of its natural gas and oil properties. Additionally, the obligations under the credit facility are guaranteed by Atlas Energy Resources, LLC and all of Atlas Energy Operating’s existing operating subsidiaries, including the managing general partner, and by any future subsidiaries, other than Anthem Securities. Borrowings under the credit facility will be available for development, exploitation and acquisition of natural gas and oil properties, working capital and general corporate purposes.
At Atlas Energy Operating’s election, interest will be determined by reference to the London interbank offered rate, or LIBOR, plus an applicable margin between 1.00% and 1.75% per annum, depending on its usage of the facility or the higher of (i) the federal funds rate plus 0.50% or (ii) the Wachovia prime rate, plus, in each case, an applicable margin between 0.00% and 0.75% per annum, depending on its usage of the facility. Interest will generally be payable quarterly for domestic bank rate loans and at the end of each applicable interest period for LIBOR loans.
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The credit facility contains covenants that, among other things, limit Atlas Energy Resources, LLC’s ability to:
| • | enter into certain leases; |
| • | make certain loans, acquisitions, capital expenditures and investments; |
| • | enter into hedging arrangements that exceed 85% of its proved reserves; |
| • | make any change to the character of its business or the business of the investment partnerships; |
| • | merge or consolidate; or |
| • | engage in certain asset dispositions, including a sale of all or substantially all of its assets. |
The credit facility requires Atlas Energy Operating to maintain a current ratio (defined as the ratio of current assets to current liabilities) of not less than 1.0 to 1.0; a funded debt to EBITDA ratio of not more than 3.5 to 1.0; and a minimum interest coverage ratio (defined as EBITDA divided by interest expense) of not less than 2.5 to 1.0. The credit facility defines EBITDA for any period of four fiscal quarters as the sum of consolidated net income for the period plus interest, income taxes, depreciation, depletion and amortization.
If an event of default exists under the credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other customary rights and remedies, including prohibiting Atlas Energy Resources, LLC from paying distributions. Each of the following is an event of default:
| • | failure to pay any principal when due or any interest, fees or other amounts in the credit facility; |
| • | failure to pay any principal or interest on any of other debt aggregating $2.5 million or more; |
| • | a representation, warranty or certification made under the loan documents or in any certificate furnished thereunder is false or misleading as of the time made or furnished in any material respect; |
| • | failure to perform under any obligation set forth in the credit facility, subject to a grace period; |
| • | an event having a material adverse effect on Atlas Energy Resources, LLC, any of the guarantors or the collateral used to secure indebtedness; |
| • | admission in writing the inability to, or being generally unable to, pay debts as they become due; |
| • | bankruptcy or insolvency events; |
| • | commencement of a proceeding or case in any court of competent jurisdiction, without application or consent, involving: |
| | • | liquidation, reorganization, dissolution or winding-up; or |
| | • | the appointment of a trustee, receiver, custodian, liquidator or the like; |
| • | the entry of, and failure to pay, one or more judgments in excess of $2.5 million; |
| • | the loan documents cease to be in full force and effect or cease to create a valid, binding and enforceable lien; |
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| • | a change of control, generally defined as (i) a group or person acquiring 35% or more of Atlas Energy Resources, LLC’s outstanding voting units (other than Atlas America and its affiliates), (ii) Atlas Energy Resources, LLC’s failure to own 85% or more of the outstanding shares of voting capital stock of any of its subsidiaries that is a guarantor under the credit facility, (iii) Atlas Energy Resources, LLC’s failure to own 100% of Atlas Energy Operating or (iv) the failure of Atlas America or any of its wholly-owned subsidiaries to own at least 51% of the equity of Atlas Management; and |
| • | concealment of property with the intent to hinder, delay or defraud any lender with respect to their rights to such property. |
The managing general partner depends on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC, and their affiliates, for management and administrative functions and financing for capital expenditures. The managing general partner paid a management fee to Atlas America for management and administrative services, as described in “Management – Transactions with Management and Affiliates.” See the footnotes to the managing general partner’s audited financial statements and the footnotes to the managing general partner’s unaudited financial statements for more details concerning the credit facility and inter-company borrowings in “Financial Information Concerning the Managing General Partner and Atlas Resources Public #16-2007(A) L.P.”
PROPOSED ACTIVITIES
Overview of Drilling Activities
The managing general partner anticipates that the subscription proceeds of each partnership will be used to drill primarily natural gas development wells, which means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Stratigraphic means a layer of rock which has characteristics that differentiate it from the rocks above and below it. Stratigraphic horizon generally means that part of a formation or layer of rock with sufficient porosity and permeability to form a petroleum reservoir. Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled.
Although the majority of the wells to be drilled by each partnership will be classified as natural gas wells, which may produce a small amount of oil, some of the wells, such as wells drilled in McKean County, Pennsylvania, if any, may be classified as oil or combination oil and natural gas wells.
Each partnership will be a separate business entity from the other partnership, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnership unless you also invest in the other partnership. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest.
Each partnership generally will drill different wells, but they may own working interests and participate in drilling and completing one or more of the same wells. The number of wells to be drilled by a partnership cannot be determined precisely before the funding of the partnership and is determined primarily by:
| • | the amount of subscription proceeds raised by the partnership; |
| • | the geographical areas in which wells are drilled by the partnership; |
| • | the partnership’s percentage of working interest owned in the wells, which could range from 25% to 100%; and |
| • | the cost of the partnership’s wells, including any cost overruns for intangible drilling costs and equipment costs of the wells which are charged to you and the other investors under the partnership agreement. |
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For the estimated number of wells to be drilled at the minimum subscription proceeds of $2 million and the maximum subscription proceeds of $200 million for a partnership, see “Risk Factors – Risks Related to an Investment in a Partnership – Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled.”
Before the managing general partner selects a prospect on which a well will be drilled by a partnership, it will review all available geologic and production data for wells located in the vicinity of the proposed well including, but not limited to:
In selecting prospects for drilling, the managing general partner will use the following criteria from adjacent prospects or in the immediate area to the extent available to it, such as production information, sand thickness, porosities and water saturations which lead the managing general partner to believe that the proposed well locations will be productive. In most cases, a prospect must be classified as proved undeveloped before the managing general partner will drill the well, which generally means that the well is being drilled to a geologic feature which contains proved reserves and is adjacent to a prospect that has or had a productive well. See the partnership agreement for the complete definition.
For example, production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. It has been the managing general partner’s experience that natural gas production from wells drilled to the formations or the reservoirs in the areas of operations discussed below in “– Primary Areas of Operations,” is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located on contiguous prospects. However, production information is only one factor, and the managing general partner may propose a well to be drilled by a partnership because geologic trends in the immediate area, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed well locations will be productive.
Primary Areas of Operations
The managing general partner will not decide on all of the specific wells to be drilled by a partnership until the offering of units in that partnership has ended. However, the managing general partner intends that Atlas Resources Public #16-2007(A) L.P. will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” These prospects represent the wells to be drilled if a portion of the nonbinding targeted subscription proceeds for that partnership, as described in “Terms of the Offering – Subscription to a Partnership,” are received. The managing general partner will substitute a new prospect if there are material adverse events with respect to any of the currently proposed prospects. For example, the managing general partner will substitute a prospect if:
| • | the latest geological and production data in the area from new wells being drilled indicates that the well may be non-productive or less productive than anticipated; |
| • | there are potential title problems; |
| • | drilling rigs, tubular goods and servic es in the area will not be available; |
| • | approvals by federal and state departments or agencies cannot be obtained; or |
| • | other properties are available that appear to be of a higher quality. |
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Also, the managing general partner has the sole discretion to sell up to and including all of the units in Atlas Resources Public #16-2007(A) L.P., and it may and not offer and sell any units in Atlas Resources Public #16-2007(B) L.P. In that event, the number of prospects identified in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” as a percentage of the total number of prospects to be drilled by Atlas Resources Public #16-2007(A) L.P. would be reduced. The managing general partner also anticipates that it will designate a portion of the prospects in the partnership designated Atlas Resources Public #16-2007(B) L.P., if units in that partnership are offered, by a supplement or an amendment to the registration statement of which this prospectus is a part.
Because not all of the prospects for each partnership will be specified, you will not be able to evaluate all of the prospects that will be drilled by your partnership. However, by waiting as long as possible before selecting all of the prospects to be drilled by a partnership, the managing general partner may acquire additional information to help it select better prospects for the partnership, and it may be able to include prospects that were not available when this prospectus was written or even when the offering of units in the partnership is closed.
The following discussion includes a general description of the areas where the managing general partner anticipates partnership wells may be drilled. All of the areas are situated in the Appalachian Basin, which is a mature producing region in the United States overlaying the states of New York, Pennsylvania, Ohio, Tennessee, West Virginia, Maryland, Kentucky and Virginia. The Appalachian Basin has well known geologic characteristics as described below, although with respect to each area listed below, the geological aspects are continually being evaluated by the managing general partner. Thus, each area discussed may ultimately include other counties which are not set forth below. For purposes of this prospectus, however, the counties listed below are generally descriptive of the specific drilling area being discussed. With the exception of the north central Tennessee area, the primary areas are situated in western Pennsylvania as discussed below. The three primary areas for the partnerships’ drilling activities are:
| • | the Mississippian/Upper Devonian Sandstone reservoirs in Fayette, Greene and Westmoreland Counties, Pennsylvania; |
| • | the Clinton/Medina geological formation which includes western Pennsylvania, primarily Crawford and Mercer Counties, Pennsylvania and also includes an area in eastern Ohio situated primarily in Stark, Mahoning, Trumbull and Portage Counties, Ohio; and |
| • | the Mississippian (carbonates) and Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. |
All of the primary areas described above have the following similarities:
| • | geological features such as structure and faulting generally are not factors used to find commercial production from a well drilled to this formation or these reservoirs and the governing factors appear to be sand or oolite (carbonate sand) quality in terms of net pay zone thickness, porosity, and the effectiveness of fracture stimulation in the well; |
| • | a well drilled to this formation or these reservoirs usually requires hydraulic fracturing of the formation to stimulate productive capacity; |
| • | generally, natural gas from a well drilled to this formation or these reservoirs is produced at rates which decline rapidly during the first few years of operations and, although the well can produce for many years, a proportionately larger amount of the well’s production can be expected within the first several years; and |
| • | it has been the managing general partner’s experience that natural gas production from wells drilled to this formation or these reservoirs is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells on contiguous prospects. Thus, as drilling progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves. |
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The managing general partner anticipates that the majority of the subscription proceeds of each partnership will be expended in the primary areas, although some of the subscription proceeds of each partnership may be expended in the secondary areas or in areas that are not currently known. Among the primary areas, the managing general partner anticipates that each partnership will drill more prospects in the Fayette County, Pennsylvania area than in the other areas. Also, see “– Secondary Areas of Operations” for a discussion of the Marcellus Shale in the Fayette County area.
Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania. The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. These reservoirs have porosities ranging from 5% to 20% with attendant permeabilities. Porosity is the percentage of void space between sand grains that is available for occupancy by either liquids or gases; and permeability is the property of porous rock that allows fluids or gas to flow through it. See the geologic evaluation prepared by United Energy Development Consultants, Inc., an independent geological and engineering firm in “Appendix A – Information Regarding Currently Proposed Prospectus for Atlas Resources Public #16-2007(A) L.P.”, for a discussion of the development of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette, Greene and Westmoreland Counties, Pennsylvania.
The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:
| • | situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; |
| • | drilled at least 1,000 feet from a producing well, although a partnership may drill a new well or re-enter an existing well that is closer than 1,000 feet to a plugged and abandoned well; |
| • | drilled to approximately 1,900 to 6,000 feet in depth; |
| • | classified as natural gas wells that may produce a small amount of oil; and |
| • | primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to UGI Energy Services, Colonial Energy, ConocoPhillips Company and Equitable Gas Company as discussed below in “– Sale of Natural Gas and Oil Production.” |
Also, see “– Secondary Areas of Operations” for a discussion of the Marcellus Shale in the Fayette County area.
Clinton/Medina Geological Formation in Western Pennsylvania. The Clinton/Medina geological formation is a blanket sandstone found throughout most of the northwestern edge of the Appalachian Basin. The Clinton/Medina geological formation in Pennsylvania and Ohio is the same geological formation, although in Pennsylvania it is often referred to as the Medina/Whirlpool geological formation. For purposes of this prospectus, the term Clinton/Medina geological formation is used for both Ohio and Pennsylvania. The Clinton/Medina geological formation is described in petroleum industry terms as a “tight” sandstone with porosity ranging from 6% to 12% and with very low natural permeability. Based on the managing general partner’s experience, it anticipates that all of the natural gas wells drilled to the Clinton/Medina geological formation will be completed and fraced in two different zones of the Clinton/Medina geological feature. See the geologic evaluation and the model decline curve prepared by United Energy Development Consultants, Inc. in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” for a discussion of the development of the Clinton/Medina Geological Formation in western Pennsylvania and eastern Ohio.
The wells in the Clinton/Medina geological formation in western Pennsylvania and eastern Ohio will be:
| • | primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull and Portage Counties, Ohio; |
| • | situated on approximately 50 acres, subject to adjustment to take into account lease boundaries; |
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| • | drilled at least 1,650 feet from each other in Pennsylvania, which is greater than the 660 feet minimum distance allowed by state law or local practice to protect against drainage from adjacent wells, and drilled at least 1,000 feet from each other in Ohio; |
| • | drilled to approximately 5,000 to 6,300 feet in depth; |
| • | classified as natural gas wells that may produce a small amount of oil, although the wells in eastern Ohio may be classified as oil wells; and |
| • | primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to Hess Corporation as discussed below in “– Sale of Natural Gas and Oil Production.” |
Also, see “– Secondary Areas of Operations” below, for a discussion of the Clinton/Medina geological formation in western New York and southern Ohio.
Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. The Mississippian carbonate reservoirs are discontinuous lens shaped accumulations found in the southern Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These reservoirs have porosities ranging from 6% to 20% with attendant permeabilities. The Devonian shale is found throughout the Appalachian Basin. When the shale is highly fractured it becomes a reservoir. See the geologic evaluation prepared by United Energy Development Consultants, Inc. in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” for a discussion of the development of the Mississippian carbonate and Devonian Shale reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee.
The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:
| • | drilled 1,320 feet from each other unless topography dictates otherwise, however, in all cases no less than 700 feet; |
| • | drilled to approximately 1,500 to 5,500 feet in depth; |
| • | classified as natural gas wells that may produce a small amount of oil; and |
| • | primarily connected to the gathering system owned by Knox Energy LLC, which is referred to as the Coalfield Pipeline, and have their natural gas production primarily marketed to Knox Energy LLC as discussed below in “– Sale of Natural Gas and Oil Production.” |
The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee were acquired from Knox Energy LLC as described below in “– Interests of Parties” and Knox Energy may participate in drilling wells in this area with the partnerships.
Secondary Areas of Operations
The managing general partner also has reserved the right to use a portion of the subscription proceeds of each partnership to drill development wells in other areas of the Appalachian Basin or elsewhere in the United States. The conditions that will prompt the managing general partner to select properties in the secondary areas are access to prospects that meet the same criteria as the primary areas, which are described in “– Overview of Drilling Activities.” However, the managing general partner does not have available to it as many prospects in the secondary areas as it does in the primary areas.
The secondary areas anticipated by the managing general partner, which are situated in the Appalachian Basin, are discussed below. Additionally, during the fourth quarter of 2006 and the first quarter of 2007, the managing general partner and an affiliated investment partnership either drilled or plan to drill three wells to multiple pay zones, including the Marcellus Shale of Southwest Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet on their acreage in Fayette, Westmoreland and Greene Counties.
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Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania. The Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. These reservoirs have porosities ranging from greater than 5% to 20% with attendant permeabilities. The prospects in Armstrong and Indiana Counties, Pennsylvania will be acquired from U.S. Energy Exploration Corporation as described below and U.S. Energy will participate in drilling the wells in this area with the partnerships.
The wells in the Upper Devonian Sandstone reservoirs will be:
| • | situated on approximately 15 acres, subject to adjustment to take into account lease boundaries; |
| • | drilled at least 1,000 feet from each other, although under Pennsylvania law in certain circumstances a variance can be obtained, and some of the wells the managing general partner has drilled to date in this general area have been drilled less than 1,000 feet apart, but even in those cases the wells were approximately 980 feet or more from each other; |
| • | drilled to approximately 1,800 to 4,400 feet in depth; |
| • | classified as natural gas wells which may produce a small amount of oil; and |
| • | connected to a gathering system owned by U.S. Energy and have their natural gas production marketed by U.S. Energy as discussed below in “– Sale of Natural Gas and Oil Production.” |
The managing general partner anticipates the leases in Armstrong and Indiana Counties, Pennsylvania will have a net revenue interest to a partnership of 84.375%. U.S. Energy, the originator of the leases, however, will retain a 25% working interest in the wells and participate with the partnership in the costs of drilling, completing, and operating the wells to the extent of its retained working interest.
Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania. See “– Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania,” above, for a description of these reservoirs. Wells located in McKean County and drilled to the Upper Devonian Sandstone reservoirs will be:
| • | situated on approximately 5 acres, subject to adjustments to take into account lease boundaries; |
| • | drilled to approximately 2,000 to 2,500 feet in depth; |
| • | classified as combination wells producing both natural gas and oil; |
| • | drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; and |
| • | connected to the gathering systems owned by Atlas Pipeline Partners and M&M Royalty, LTD. and have their natural gas production primarily marketed to M&M Royalty, LTD. as discussed below in |
“– Sale of Natural Gas and Oil Production.”
Clinton/Medina Geological Formation in Western New York. Wells located in western New York and drilled to the Clinton/Medina geological formation will be:
| • | primarily situated in Chautauqua County; |
| • | situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; |
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| • | drilled to approximately 3,800 to 4,000 feet in depth; |
| • | drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; |
| • | classified as natural gas wells which may produce a small amount of oil; and |
| • | connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to Hess Corporation, commercial end users in the area, and/or Great Lakes Energy Partners, L.L.C. as discussed below in “– Sale of Natural Gas and Oil Production.” |
Clinton/Medina Geological Formation in Southern Ohio. Wells located in southern Ohio and drilled to the Clinton/Medina geological formation will be:
| • | primarily situated in Noble, Washington, Guernsey, and Muskingum Counties; |
| • | situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; |
| • | drilled at least 1,000 feet from each other; |
| • | drilled to approximately 4,900 to 6,500 feet in depth; |
| • | drilled on leases with a net revenue interest of approximately 82.5% to 87.5%; |
| • | classified as either natural gas wells or oil wells; and |
| • | primarily connected to the gathering system owned by Atlas Pipeline Partners (if classified as natural gas wells) and have their natural gas production marketed to Hess Corporation, although a portion of the natural gas production may be gathered and marketed by Triad Energy Corporation of West Virginia, Inc. as discussed below in “– Sale of Natural Gas and Oil Production.” |
Additionally, the managing general partner anticipates that the leases in southern Ohio will have been originally acquired from a coal company and are subject to a provision that the well must be abandoned if it hinders the development of the coal. Thus, the managing general partner will not drill a well on any lease subject to this provision unless it covers lands that were previously mined. Although this does not totally eliminate the risk because the leases may cover other coal deposits that might be mined during the life of a well, the managing general partner believes that drilling wells on these previously mined leases would be in the best interests of the partnerships.
Acquisition of Leases
The managing general partner will have the right, in its sole discretion, to select the prospects which each partnership will drill. The managing general partner intends that Atlas Resources Public #16-2007(A) L.P. will drill the prospects described in “Appendix A – Information Regarding Currently Proposed Prospects for Atlas Resources Public #16-2007(A) L.P.” The managing general partner also anticipates that it will designate a portion of the prospects in Atlas Resources Public #16-2007(B) L.P., if units in that partnership are offered, by means of a supplement or an amendment to the registration statement of which this supplement is a part.
The leases covering each prospect on which one well will be drilled will be acquired by a partnership from the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution to the partnership. Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well.
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The managing general partner anticipates that it will select the prospects for each partnership, including any additional and/or substituted prospects, from the following:
| • | leases in its and its affiliates’ existing leasehold inventory; |
| • | leases that are subsequently acquired by it or its affiliates; or |
| • | leases owned by independent third-parties that may participate with the partnership in drilling wells. |
The majority of the prospects acquired by a partnership will be in areas where the managing general partner or its affiliates have previously conducted drilling operations. The managing general partner believes that its and its affiliates’ leasehold inventory and leases acquired from third-parties will be sufficient to provide all the development prospects to be drilled by the partnerships if the targeted maximum subscription proceeds of $200 million are received. In this regard, the managing general partner and its affiliates are continually engaged in acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of the United States. As of August 15, 2006, the managing general partner’s and its affiliates’ undeveloped leasehold acreage was as follows:
| | Undeveloped Lease Acreage | |
| |
| |
| | Gross | | Net (1) | |
| |
| |
| |
Kentucky | | 9,060 | | 4,530 | |
Montana | | 2,650 | | 2,650 | |
New York | | 38,534 | | 38,534 | |
Ohio | | 37,851 | | 34,414 | |
Pennsylvania | | 189,910 | | 189,910 | |
West Virginia | | 10,806 | | 5,403 | |
Wyoming | | 80 | | 80 | |
| |
| |
| |
Total | | 288,891 | | 275,521 | |
| |
| |
| |
(1) | The net acreage as to which leases expire in fiscal 2007 are as follows: Ohio: 2007 – 1,538 acres and Pennsylvania: 2007 – 12,938 acres. |
Most, if not all, of the prospects to be selected for the partnerships are expected by the managing general partner to be single well proved undeveloped prospects that are classified as developmental. Thus, only one well will be drilled on each of those prospects and the number of prospects that the managing general partner will assign to each partnership will be the same as the number of wells that the partnership has the funds to drill. This also means that the partnership, in all likelihood, will not farmout any acreage associated with those prospects. However, the need for a farmout might arise, for example, if during drilling or subsequently the managing general partner determines there might be a productive horizon situated above (i.e. uphole) the target horizon, but the partnership does not have the funds to complete the well in the horizon or the completion of the horizon would be inconsistent with the partnership’s objectives. In this event, the managing general partner might decide to farmout the activity for the partnership. Generally, a farmout is an agreement in which the owner of the lease or existing well agrees to assign its interest in certain acreage under the lease or the existing well to an assignee subject to the assignee drilling one or more wells or completing or recompleting the existing well in one or more horizons. The owner would retain some interest in the assigned acreage or well. See “Conflicts of Interest – Conflicts Involving the Acquisition of Leases” for the procedure for a farmout, and “Federal Income Tax Consequences – Farmouts.”
Deep Drilling Rights Retained by Managing General Partner. The lease assignments to each partnership generally will be limited to a depth from the surface to the deepest depth penetrated at the cessation of drilling operations. The managing general partner will retain the deeper drilling rights, including ownership of any coal bed methane production that might be obtained from the deeper formations. Conversely, as between a partnership and the managing general partner, the partnership will own any coal bed methane production that might be obtained from the shallower formations that are not included in the deeper drilling rights retained by the managing general partner.
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The amount of the credit the managing general partner receives for the leases it contributes to a partnership will not include any value allocable to the deeper drilling rights retained by it. If the managing general partner undertakes any activities with respect to the deeper formations in the future, then the partnerships would not share in the profits from these activities, nor would the partnerships pay any of the associated costs.
Interests of Parties
Generally, production and revenues from a well drilled by a partnership will be net of the applicable landowner’s royalty interest, which is typically 1/8th (12.5%) of gross production, and any interest in favor of third-parties such as an overriding royalty interest. Landowner’s royalty interest generally means an interest that is created in favor of the landowner when an oil and gas lease is obtained; and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation, or maintenance of the well. This is compared with a working interest, which generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation, or maintenance of the well. Also, the leases will be subject to terms that are customary in the industry such as free gas to the landowner-lessor for home heating requirements, etc.
The managing general partner anticipates that each partnership generally will have a net revenue interest in its leases in its primary drilling areas as set forth in the chart below. Net revenue interest generally means the percentage of revenues the owner of an interest in a well is entitled to receive under the lease. The following chart expresses the percentage of production revenues that the managing general partner, the landowner, other third-parties, and you and the other investors in a partnership will share in from the wells in two of the three primary drilling areas. The third primary drilling area in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee is discussed following the chart. The chart assumes that the partnership owns 100% of the working interest in the well. If a partnership acquires a lesser percentage working interest in a well, which may be the case in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, then the partnership’s net revenue interest in that well will decrease proportionately.
The actual number, identity and percentage of working interests or other interests in prospects to be acquired by the partnerships will depend on, among other things:
| • | the amount of subscription proceeds received by a partnership; |
| • | the latest geological and production data; |
| • | potential title or spacing problems; |
| • | availability and price of drilling services, tubular goods and services; |
| • | approvals by federal and state departments or agencies; |
| • | agreements with other working interest owners in the prospects; |
| • | farmins and farmouts; and |
| • | continuing review of other prospects that may be available. |
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Primary Areas.
Mississippian/Upper Devonian Sandstone Reservoirs in Fayette County, Pennsylvania.
Entity | | | Partnership
Interest | | Third Party
Royalty Interest | | 87.5% Partnership
Net Revenue Interest (2) | |
| | |
| |
| |
| |
Managing General Partner | 32% | | partnership interest (1) | | | | 28.0 | % |
Investors | 68% | | partnership interest (1) | | | | 59.5 | % |
Third Party | | | | | 12.5% Landowner Royalty Interest | | 12.5 | % |
| | | | | | |
| |
| | | | | | | 100.0 | % |
| | | | | | |
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(1) | These percentages are for illustration purposes only, and assume that the partnership has a 100% working interest and the managing general partner contributes its minimum required capital contribution of 25% to each partnership and the capital contributions from you and the other investors are 75%. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner’s total revenue share may not exceed 40% of partnership revenues regardless of the amount of its capital contributions. |
Clinton/Medina Geological Formation in Western Pennsylvania.
Entity | | | Partnership
Interest | | Third Party Royalty Interest | | 84.375% Partnership Net Revenue Interest (2) | |
| | |
| |
| |
| |
Managing General Partner | 32% | | partnership interest (1) | | | | 30.125 | % |
Investors | 68% | | partnership interest (1) | | | | 57.375 | % |
Third Party | | | | | 12.5% Landowner Royalty Interest | | 12.500 | % |
| | | | | | |
| |
| | | | | | | 100.000 | % |
| | | | | | |
| |
(1) | These percentages are for illustration purposes only, and assume that the partnership has a 100% working interest and the managing general partner contributes its minimum required capital contribution of 25% to each partnership and the capital contributions from you and the other investors are 75%. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner’s total revenue share may not exceed 40% of partnership revenues regardless of the amount of its capital contributions. |
Mississippian Carbonate and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. Generally, the leases in north central Tennessee will have a net revenue interest to a partnership ranging from 84.375% to 81.375%, assuming that a partnership has a 100% working interest. However, the amount of the partnership’s net revenue interest in some of the prospects could be as low as 81.375% depending primarily on whether the landowner royalty interest is 12.5% or 15.5%. The amount of the landowner royalty depends, in turn, on whether the natural gas produced from those prospects, if any, is sold at a price above or below $3.00 per mcf, and on whether Knox Energy LLC and its affiliates, the originators of the leases, participate as a working interest owner with a partnership in the leases covering those prospects. Knox Energy and its affiliates may retain up to a 50% working interest in the wells and participate with the partnership in the costs of drilling, completing, and operating the wells to the extent of its retained working interest. Also, if Knox Energy does not retain a working interest in a well, then its overriding royalty interest will be 3.125%. However, if Knox Energy retains a 50% working interest in a well, then its overriding royalty interest of 3.125% will be reduced to 1.5625%. To the extent that Knox Energy participates in a well as a working interest owner for less than a 50% working interest, its overriding royalty interest will be prorated between 3.125% and 1.5625% depending on the percentage of its working interest. The investors’ net revenue interest in the above example would range from 57.375% to 55.335%, if presented on a 100% working interest basis and the investors were receiving 68% of the partnership revenues.
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Pursuant to the acquisition terms of the agreement between the managing general partner and its affiliates and Knox Energy and its affiliates, no well drilled by the managing general partner and its affiliates in this area, which includes the partnerships, may produce coalbed methane gas, and the managing general partner or its affiliates must drill 300 commitment wells during the initial three year term of the agreement with Knox Energy, which ends June 30, 2007, or they will be in breach of the agreement.
Secondary Areas
Although the managing general partner anticipates that each partnership will have a net revenue interest ranging from 81% to 87.5% in its leases in the secondary areas described above, assuming it owns 100% of the working interest, there is no minimum net revenue interest that a partnership is required to own before drilling a well in other areas of the United States. The leases in these other areas may be subject to interests in favor of third-parties that are not currently known such as overriding royalty interests, net profits interests, carried interests, production payments, reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements, or other retained or carried interests.
Title to Properties
Title to all leases acquired by a partnership ultimately will be held in the name of the partnership. However, to facilitate a partnership’s acquisition of the leases title to the leases may initially be held in the name of the managing general partner, the operator, their affiliates, or any nominee designated by the managing general partner. Title to each partnership’s leases will be transferred to the partnership and filed for record from time to time after the wells are drilled and completed.
The managing general partner will take the steps it deems necessary to assure that each partnership has acceptable title for its purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for the leases it assigns to a partnership. The managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will not obtain a division order title opinion after the well is completed. The managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of the leases transferred to a partnership. Also, the partnerships may experience losses from title defects excluded from, or not disclosed by, the formal title opinion that is provided to the managing general partner before a well is drilled or that would have been disclosed by a division order title opinion after the well is drilled, if the partnership obtained division order title opinions, which it will not do. Although past performance is no guarantee of future results, the previous drilling partnerships sponsored by the managing general partner and its affiliates have participated in drilling more than 3,220 wells in the Appalachian Basin since 1985, and none of the wells have been lost because of title failure. (See “Prior Activities.”)
Drilling and Completion Activities; Operation of Producing Wells
On receipt of the minimum subscription proceeds of a partnership, the managing general partner on behalf of the partnership may break escrow, transfer the escrowed funds to a partnership account, enter into the drilling and operating agreement, which is attached to the partnership agreement as Exhibit II, with itself or an affiliate of the managing general partner as operator, and begin drilling the partnership’s wells.
Under the drilling and operating agreement, the responsibility for drilling and either completing or plugging partnership wells will be on the managing general partner or an affiliate of the managing general partner as the operator and the general drilling contractor. Under the drilling and operating agreement, each partnership is required to prepay the investors’ share of the drilling and completion costs of its wells to the managing general partner as the general drilling contractor and operator. If one or more of a partnership’s wells will be drilled in the calendar year after the year in which the advance payment is made, the required advance payment allows the partnership to secure tax benefits of prepaid intangible drilling costs based on a substantial business purpose for the advance payment under the drilling and operating agreement. The managing general partner as operator and general drilling contractor will begin drilling all of the wells no later than March 30, 2008 for the partnerships. (See “Federal Income Tax Consequences – Drilling Contracts.”)
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During drilling operations the managing general partner’s duties as operator and general drilling contractor will include:
| • | making the necessary arrangements for drilling and completing partnership wells and related facilities for which it has responsibility under the drilling and operating agreement; |
| • | managing and conducting all field operations in connection with drilling, testing, and equipping the wells; and |
| • | making the technical decisions required in drilling and completing the wells. |
All partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation unless the managing general partner determines in its sole discretion that the well shall be completed in a formation uphole from the objective geological formation.
Under the drilling and operating agreement the managing general partner, as operator and general drilling contractor, will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. However, based on its past experience, the managing general partner anticipates that most of the development wells drilled by the partnerships in the primary and secondary areas will have to be completed before the managing general partner can determine the well’s productivity. If the managing general partner, as operator and general drilling contractor, determines that a well should not be completed, then the well will be plugged and abandoned.
During producing operations the managing general partner’s duties, as operator, will include:
| • | managing and conducting all field operations in connection with operating and producing the wells; |
| • | making the technical decisions required in operating the wells; and |
| • | maintaining the wells, equipment, and facilities in good working order during their useful life. |
The managing general partner, as operator, will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates for operating and maintaining the wells during producing operations as discussed in “Compensation.” As discussed in “Summary of Drilling and Operating Agreement,” the drilling and operating agreement contains a number of other material provisions which you are urged to review.
Certain wells may be drilled by a partnership with third-parties owning a portion of the working interest in the wells. Any other working interest owner in a well will have a separate agreement with the managing general partner for drilling and operating the well with differing terms and conditions from those contained in a partnership’s drilling and operating agreement. (See “Federal Income Tax Consequences – Drilling Contracts.”)
Sale of Natural Gas and Oil Production
Policy of Treating All Wells Equally in a Geographic Area. All benefits and liabilities from marketing and hedging arrangements or other relationships affecting the property of the managing general partner or its affiliates and the partnerships shall be fairly and equitably apportioned according to the respective interests of each in the property. The managing general partner is responsible for selling each partnership’s natural gas and oil production, and its policy is to treat all wells in a given geographic area equally. This reduces certain potential conflicts of interest among the owners of the various wells, including the partnerships sponsored by the managing general partner, concerning to whom and at what price the natural gas and oil will be sold. For example, the managing general partner calculates a weighted average selling price for all of the natural gas sold in the geographic area and this is the price which will be paid to each partnership in the geographic area for its natural gas. For natural gas sold in western Pennsylvania during its previous four fiscal years, the managing general partner received an average selling price after deducting all expenses, including transportation expenses and after the effects of hedging arrangements, of approximately:
| • | $3.34 per mcf, “mcf” means 1,000 cubic feet of natural gas, in 2002; |
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| • | $5.64 per mcf in 2004; and |
If all of the natural gas produced in an area cannot be sold by the managing general partner and its affiliates, including the partnerships, because of limited gathering line or pipeline capacity, or limited demand for the natural gas, which increases pipeline pressure, then the production that is sold will be from those wells that have the greatest well pressure and are able to feed into the pipeline, regardless of which partnerships own the wells. The proceeds from these natural gas sales will be credited only to the partnerships whose wells produced the natural gas sold.
Gathering of Natural Gas. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and/or end-users in the area. For the majority of each partnership’s natural gas production, including natural gas in the primary areas, as discussed below, the managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership), which is a master limited partnership formed by a subsidiary of Atlas America as managing general partner using Atlas America personnel who act as its officers and employees. (See “Management – Organizational Diagram and Security Ownership of Beneficial Owners.”) Atlas Pipeline Partners acquired the natural gas gathering system and related facilities of Atlas America, Resource Energy, and Viking Resources in February 2000. The gathering system consists of more than 1,400 miles of intrastate pipelines located in western Pennsylvania, eastern Ohio, and western New York.
If a partnership’s natural gas is not transported through the Atlas Pipeline Partners gathering system, it is because there is a third-party operator or the gathering system has not been extended to the wells. In these cases, which includes the McKean County area and the north central Tennessee area, as described in “Compensation – Gathering Fees,” the natural gas will be transported through a third-party gathering system, and the partnership will pay the managing general partner a competitive gathering fee, all of which will be paid by it to the third-party. Also, in the north central Tennessee area, the managing general partner and its affiliates may construct a gathering system in the future for which they will receive gathering fees as described in “Compensation – Gathering Fees.”
As a part of the sale of the gathering system to Atlas Pipeline Partners in February 2000, Atlas America and its affiliates, Resource Energy and Viking Resources (the “Atlas entities”), made certain commitments that were intended to maximize the use and expansion of the gathering system. Those commitments were made pursuant to a master natural gas gathering agreement and an omnibus agreement which were entered into at the time of sale in February 2000. Both the master natural gas gathering agreement and the omnibus agreement set forth continuing obligations of the Atlas entities that have no specified term, except that they will terminate with respect to future wells drilled by the Atlas entities if the general partner of Atlas Pipeline Partners, L.P., Atlas Pipeline Partners GP, LLC (which is owned by Atlas Pipeline Holdings, L.P., a limited partnership that recently completed a public offering as described in “Management – Organizational Diagram and Security Ownership of Beneficial Owners”) is removed without cause and without its consent. However, under the master natural gas gathering agreement the Atlas entities, including the partnerships in this case, have committed the natural gas production from the wells they drill before removal of Atlas Pipeline Partners GP, LLC without cause and without its consent, for the life of the wells. Thus, the termination of the master natural gas gathering agreement under the circumstance described above will only terminate the obligation of the Atlas entities, including the partnerships, to transport their natural gas through Atlas Pipeline Partners’ gathering system with respect to wells drilled on or after the termination of the agreement. Some of these commitments still affect the partnerships. For example, under the master natural gas gathering agreement the Atlas entities are required to pay a gathering fee to Atlas Pipeline Partners equal to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported through Atlas Pipeline Partners’ gathering system. If a partnership pays a lesser amount, which is anticipated by the managing general partner as described in “Compensation – Gathering Fees,” then the Atlas entities must pay the difference to Atlas Pipeline Partners. Also, if Atlas Pipeline Partners determines that the continued operation of any part of the gathering system is not economically justified, then it may elect to discontinue the operation of that portion of the gathering system. If Atlas Pipeline Partners makes this determination, then it must give the parties to the agreement the right to purchase that part of the gathering system for $10. Pursuant to an amendment and joinder to the gas gathering agreements, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC became parties to the existing master natural gas gathering agreement. Also pursuant to the amendment and joinder agreement, Atlas America was removed as a party to the gas gathering agreement with Atlas Pipeline relating to wells owned by third parties unrelated to Atlas Energy Resources, LLC or its investment partnerships. As described in “Management,” Atlas America has assumed Atlas Energy Resources, LLC’s obligations under that agreement to pay the gathering fees to Atlas Pipeline, and Atlas Energy Resources, LLC agreed to pay Atlas America the gathering fees it receives from the partnerships and the managing general partner’s other investment partnerships. If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with Atlas Energy Resources, LLC, Atlas Energy Resources, LLC will have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount it receives from the investment partnerships for gathering services out of its own resources.
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Under the omnibus agreement, Atlas America is required to commit to Atlas Pipeline Partners’ gathering system all wells it drills and operates, including those of the partnerships, that are within 2,500 feet of the Atlas Pipeline Partners gathering system. In addition, the Atlas entities, including the partnerships, must construct at their own cost, up to 2,500 feet of flowline as necessary to connect their wells to Atlas Pipeline Partners’ gathering system. Also, Atlas Pipeline Partners must, at its own cost, extend its gathering system to connect to any flowlines constructed by the Atlas entities, including the partnerships, that are within 1,000 feet of its gathering system. With respect to wells to be drilled by Atlas America and its affiliates, including the partnerships, that will be more than 3,500 feet from Atlas Pipeline Partners’ gathering system, Atlas Pipeline Partners has various options, in its discretion, to connect those wells to its gathering system at its own cost. Also, Atlas America and its affiliates may not divest their ownership of Atlas Pipeline Partners GP, LLC without also divesting their ownership of the entities serving as managing general partner in all of their affiliated investment partnerships, including the partnerships, to the same acquirer, except that Atlas America is permitted to transfer its ownership interest in Atlas Pipeline Partners GP, LLC to a wholly- or majority-owned direct or indirect subsidiary as long as Atlas America continues to control that subsidiary. See “Management – Organizational Diagram and Security Ownership of Beneficial Owners,” regarding the public offering in Atlas Pipeline Holdings, L.P., which owns Atlas Pipeline Partners GP, LLC. Pursuant to an amendment and joinder to omnibus agreement, Atlas Energy Resources, LLC and Atlas Energy Operating Company, LLC became parties to the existing omnibus agreement between Atlas America and Atlas Pipeline which sets forth the obligations that Atlas Energy Resources, LLC, Atlas America and Atlas Pipeline will have to connect wells to the Atlas Pipeline gathering systems and that Atlas Energy Resources, LLC will have to provide consultation services in the construction of new gathering systems or the extension of existing systems. Because Atlas Energy Resources, LLC owns substantially all of Atlas America’s natural gas and oil development and production business, Atlas Energy Resources, LLC will be primarily liable under the omnibus agreement, and Atlas America will be secondarily liable as a guarantor of Atlas Energy Resources, LLC’s performance.
Natural Gas Contracts. As set forth in “– Primary Areas of Operations,” each partnership has three primary areas where it will drill its wells, and the managing general partner anticipates that there will be a different natural gas purchaser or purchasers in each area. The managing general partner anticipates that more prospects will be drilled in the Mississippian/Upper Devonian Sandstone Reservoirs in the Fayette County, Pennsylvania 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 Company 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, 2007. After this contract ends, it is anticipated that Atlas America will market its production in the future to purchasers which are not currently known. The managing general partner anticipates that the remainder of the natural gas produced by the partnership from wells drilled in the other primary area, which is the Crawford County area of the Clinton/Medina geological formation in western Pennsylvania, and the secondary areas, other than the Upper Devonian Sandstone Reservoirs in Armstrong and McKean Counties, Pennsylvania, will be sold to Hess Corporation (“Hess”) until April 1, 2007, as discussed below. After April 1, 2007, it is anticipated 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 each partnership based on the volume of natural gas produced by each partnership. Until the sales proceeds are distributed to the partnerships, they will be subject to the claims of Atlas America’s, Atlas Energy Resources, LLC’s or their affiliates’ creditors.
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The managing general partner and its affiliates previously entered into a 10-year agreement with First Energy Solutions Corporation. This agreement 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 the managing general partner and its affiliates, which includes each partnership and the managing general partner’s other partnerships, 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 the managing general partner and its affiliates because as of July 31, 2006 the 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, each partnership will sell a much smaller percentage of its natural gas to Hess because of certain exceptions to the agreement, including natural gas sold through interconnects established after the agreement, which includes the 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. Also, after April 1, 2007 natural gas production from Crawford County, Pennsylvania will be sold to Interstate Gas Supply, Inc., instead of Hess, 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 the managing general partner and its affiliates has ranged between $0.51 to $1.07 per Mcf during the managing general partner’s past three fiscal years. These figures are based on the overall weighted average that the 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 the managing general partner’s and its partnerships’ exposure to decreases in natural gas prices, the 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 the 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, the managing general partner has established a committee to assure that all financial trading is done in compliance with the managing general partner’s hedging policies and procedures. The 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 the 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, the 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 value. As of April 2, 2006, a portion of the managing general partner’s natural gas was subject to physical hedges through March 31, 2007. After March 31, 2007, none of the managing general partner’s and its affiliates’ natural gas is subject to physical hedges and the managing general partner and its affiliates anticipate using financial hedges as discussed below for all of its natural gas that is hedged, although this may change from time to time.
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On October 27, 2005, Atlas America implemented financial hedges through its banking counter-party, Wachovia Bank, and as of October 2, 2006, Atlas America on behalf of the partnerships and the other partnerships sponsored by the managing general partner, hedged approximately 51% of their natural gas production using fixed-for-floating financial swaps for the period April 1, 2007 through December 31, 2009. Atlas America and/or Atlas Energy Resources, LLC and their affiliates are also negotiating with other banking counter-parties to implement financial hedges. In this regard, the partnerships 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 the managing general partner to Atlas Energy Resources, LLC, a subsidiary of Atlas Energy Resources, LLC, rather than Atlas America, will enter into these hedging arrangements.
The percentages of natural gas that is 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 each partnership by the managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by a partnership. Although hedging provides the partnerships some protection against falling prices, these activities also could reduce the potential benefits of price increases and the partnerships could incur liability on the financial hedges. For example, if a partnership’s 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 a partnership would be exposed to the risk of a financial loss. Subject to the 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 the managing general partner or its affiliates or the partnerships 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 the managing general partner to the partnerships and the other partnerships sponsored by the managing general partner and its affiliates pro rata based on actual production, consistent with past practice, and the partnerships and the other partnerships sponsored by the managing general partner and its affiliates will be severally liable for their 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 those liabilities, or be entitled to any of those benefits, to the extent they are allocated to the partnerships and the other partnerships sponsored by the managing general partner and its affiliates.
Marketing of Natural Gas Production from Wells in Other Areas of the United States. The managing general partner expects that natural gas produced by the partnership from wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:
| • | local distribution companies; |
| • | industrial or other end-users; and/or |
| • | companies generating electricity. |
Crude Oil. Crude oil produced from a partnership’s 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. The managing general partner anticipates selling any oil produced by the wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales. The managing general partner received an average selling price for oil during its previous four fiscal years of approximately $18.92 per barrel in 2002; $29.06 per barrel in 2003; $34.41 per barrel in 2004; and $50.00 per barrel in 2005. During the term of the partnerships it is anticipated that the price of oil will be uncertain and volatile.
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Insurance Claims
Since 1972 the managing general partner and its affiliates, including its partnerships, have been involved in drilling more than 5,300 wells, most of which were developmental wells, in Ohio, Pennsylvania, and other areas of the Appalachian Basin. They have made only one material insurance claim and, as discussed below, one which may evolve into a material claim. In February 2004, one of the wells in another investment partnership incurred an uncontrolled flow of natural gas and oil with a fire during drilling. These problems with the well were subsequently controlled, but they resulted in the loss of a subcontractor’s drilling rig and third-party claims. As of April 19, 2005, the managing general partner’s insurance carrier had paid approximately $1.6 million to third-parties for property damage claims and additional claims have been submitted which have not yet been paid. The managing general partner’s insurance company is exploring all avenues for subrogation. In addition, in February 2006, there was a well fire during the drilling of a well in Fayette County, Pennsylvania which resulted in a claim against the managing general partner’s insurance carrier in an amount which has not been quantified. See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners – Insurance” for a discussion of the insurance coverage the managing general partner intends to be available for a partnership’s benefit.
Use of Consultants and Subcontractors
The partnership agreement authorizes the managing general partner to use the services of independent outside consultants and subcontractors on behalf of the partnerships. The services will normally be paid on a per diem or other cash fee basis and will be charged to the partnership on whose behalf the costs were incurred as either a direct cost or as a direct expense under the drilling and operating agreement. These charges will be in addition to the costs of subcontractor services provided by the managing general partner’s affiliates, which will be charged at competitive rates, and the oversight and administration fee that will be paid to the managing general partner during drilling operations, and the well supervision fees paid to the managing general partner as operator as discussed in “Compensation.”
COMPETITION, MARKETS AND REGULATION
Natural Gas Regulation
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 further 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 also has required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices.
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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.
Competition and Markets
Many companies engage in natural gas and oil drilling operations in the Appalachian Basin, where most or all of the wells in each partnership will be located. According to the Energy Information Administration, the independent statistical and analytical agency within the Department of Energy, in 2004 there were 23 quadrillion BTU of natural gas consumed in the United States which represented approximately 23% of the total energy used. The Appalachian Basin accounted for approximately 5.7% of the total domestic natural gas production in the United States in 2004 and represented approximately 12.5% of the total number of wells drilled in the United States during 2004. Also, according to the Natural Gas Annual 2004 Report, which is published by the Energy Information Administration Office of Oil and Gas, as of December 31, 2004, the Appalachian Basin’s economically recoverable natural gas reserves represented approximately 8% of total domestic natural gas reserves.
The natural gas and oil industry is highly competitive in all phases. In this regard, the partnerships will operate in a highly competitive environment for acquiring leases, contracting for drilling equipment, securing trained personnel and marketing natural gas and oil production from their respective wells. For example, the Pennsylvania Bureau of Oil and Gas Management estimates that in 2005 there were 747 well operators bonded in Pennsylvania, which includes two of the partnerships’ primary drilling areas. Product availability and price are the principal means of competing in selling natural gas and oil. Many of the partnerships’ competitors will have financial resources and staffs larger than those available to the partnerships. This may enable them to identify and acquire desirable leases and market their natural gas and oil production more effectively than the managing general partner and the partnerships. While it is impossible to accurately determine the partnerships’ industry position, the managing general partner does not consider that the partnerships’ intended operations will be a significant factor in the industry.
The natural gas and oil industry has from time to time experienced periods of rapid cost increases. The increase in natural gas and oil prices over the last several years also has increased the demand for drilling rigs and other related equipment and the costs of drilling and completing natural gas and oil wells. Additionally, the managing general partner and its affiliates have experienced an increase in the cost of tubular steel used in drilling wells. Because each partnership’s wells will be drilled on a modified cost plus basis as described in “Compensation – Drilling Contracts,” these increased costs will increase the partnerships’ costs to drill and complete their wells. Also, the reduced availability of drilling rigs and other related equipment may make it more difficult to drill each partnership’s wells in a timely manner or to comply with the prepaid intangible drilling costs rules discussed in “Federal Income Tax Consequences – Drilling Contracts.” Further, over the term of each partnership there may be fluctuating or increasing costs in doing business which directly affect the managing general partner’s ability to operate the partnership’s wells at acceptable price levels.
The natural gas and oil produced by your partnership’s wells must be marketed in order for you to receive revenues. During its fiscal years ending in 2005, 2004, and 2003, the managing general partner did not experience any problems in selling natural gas and oil, although the prices varied significantly during those periods. As set forth above, natural gas and oil prices are not regulated, but instead are subject to factors which are generally beyond the partnerships’ and the managing general partner’s control such as the supply and demand for natural gas and oil. 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 also beyond the control of the managing general partner and the partnerships 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; |
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| • | 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; |
| • | 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 the 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. |
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 the partnerships’ wells.
The managing general partner is unable to predict what effect the various factors set forth above will have on the future price of the natural gas and oil sold from the partnerships’ wells. According to the Annual Energy Outlook 2006 with Projections to 2030 published by the Energy Information Administration (EIA), total natural gas consumption is projected to increase from 22.34 trillion cubic feet in 2003 to 26.86 trillion cubic feet by 2030. Over that same period, total natural gas supplies are projected to grow by 4.08 trillion cubic feet, with domestic natural gas production expected to account for 45% of the total growth in gas supply, and net imports projected to account for the remainder. Notwithstanding, wellhead natural gas prices are projected to decline in the early years of the forecast as a result of the following responses to the current high prices:
| • | an increase in drilling levels; |
| • | the coming online of new natural gas production; and |
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| • | the increase in liquid natural gas (“LNG”) imports. |
After 2011, however, natural gas prices are projected to increase in response to the higher exploration and development costs associated with smaller and deeper natural gas deposits in the remaining domestic natural gas resource base. Also, the managing general partner believes there have been several developments which may increase the demand for natural gas, but may or may not be offset by an increase in the supply of natural gas, which the managing general partner is unable to predict. For example, the Clean Air Act Amendments of 1990 contain incentives for the future development of “clean alternative fuel,” which includes natural gas and liquefied petroleum gas for “clean-fuel vehicles.” Also, the accelerating deregulation of electricity transmission has caused a convergence between the natural gas and electric industries. In 2004, according to information from the Energy Information Administration, the breakout of energy sources for the generation of electricity in the United States was as follows:
| • | natural gas fired power plants were used to produce approximately 18%; |
| • | coal-fired power plants were used to produce approximately 50%; |
| • | nuclear power plants were used to produce approximately 20%; and |
| • | large scale hydroelectric projects were used to produce approximately 7%. |
In recent years, the electricity industry has increased its use of natural gas because of increased competition and the enforcement of stringent environmental regulations. For example, the Environmental Protection Agency has sought to enforce environmental regulations which increase the cost of operating coal-fired power plants. According to the Energy Information Administration, the demand for natural gas by producers of electricity is expected to increase through the decade. Also, the last nuclear power plant to come online in the United States was in June 1996, although the existing nuclear power plants have increased their capacity and the recent energy act includes tax credits for constructing new nuclear power plants. Unless the price of natural gas increases to a point where it becomes uneconomic as an energy source as compared to alternate energy sources, the managing general partner believes that natural gas is the preferred fuel for many producers of electricity since many electricity producers have begun moving away from dirtier-burning fuels, such as coal and oil because of environmental compliance requirements. In this regard, some of the new natural gas fired power plants which are coming into service are not designed to allow for switching to other fuels.
State Regulations
Natural gas and oil operations are regulated in Pennsylvania by the Department of Environmental Resources and in Tennessee by the Department of Environment and Conservation. Pennsylvania, Tennessee and the other states where each partnership’s wells may be situated impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, these 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; |
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| • | various reporting requirements; and |
| • | well plugging standards and procedures. |
These state regulatory agencies also have broad regulatory and enforcement powers including those associated with pollution and environmental control laws, which are discussed below.
Environmental Regulation
Each partnership’s drilling and producing operations will be 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 the partnerships 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 that will increase if there was willful negligence or misconduct. In addition, the partnerships 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 a partnership’s drilling activities or its wells and its production activities.
Each partnership and its investor general partners may incur environmental costs and liabilities due to the nature of the partnership’s business and substances from the partnership’s wells as described “Risk Factors.” For example, an accidental release from one of a partnership’s wells could subject the partnership to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third-parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted in the future which could significantly increase a partnership’s compliance costs and the cost of any remediation that may become necessary.
Also, a partnership’s liability can extend to pollution costs that occurred on the leases before they were acquired by the partnership. Although the managing general partner will not transfer any lease to a partnership if it has actual knowledge that there is an existing potential environmental liability on the lease, there will not be an independent environmental audit of the leases before they are transferred to a partnership. Thus, there is a risk that the leases will have potential environmental liability even before drilling begins.
A partnership’s required compliance with these environmental laws and regulations may cause delays or increase the cost of the partnership’s drilling and producing activities. Because these laws and regulations are frequently changed, the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. Also, the managing general partner is unable to obtain insurance to protect against many environmental claims, including remediation costs.
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Proposed Regulation
From time to time there are a number of proposals considered in Congress and in the legislatures and agencies of various states that if enacted would significantly and adversely affect the natural gas and oil industry and the partnerships. The proposals involve, among other things:
| • | limiting the disposal of waste water from wells or the emission of greenhouse gases, which could substantially increase a partnership’s operating costs and make the partnership’s wells uneconomical to produce; |
| • | changes in the federal income tax benefits for drilling natural gas and oil wells as discussed in “Federal Income Tax Consequences”; and |
| • | tax credits and other incentives for the creation or expansion of alternative energy sources to natural gas and oil. |
Also, Congress could re-enact price controls or additional taxes on natural gas and oil in the future. However, it is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on a partnership’s activities.
PARTICIPATION IN COSTS AND REVENUES
In General
The partnership agreement provides for the sharing of partnership costs and revenues among the managing general partner and you and the other investors. A tabular summary of the following discussion appears below. Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets, or tax benefits of the other partnership unless you also invest in the other partnership. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest.
Costs
1. | Organization and Offering Costs. Organization and offering costs will be charged 100% to the managing general partner. However, the managing general partner will not receive any credit towards its required capital contribution or its revenue share for any organization and offering costs charged to it in excess of 15% of a partnership’s subscription proceeds. |
| • | Organization and offering costs generally means all costs of organizing and selling the offering and includes the dealer-manager fee, sales commissions and the up to .5% reimbursement for bona fide due diligence expenses. |
The managing general partner will pay a portion of a partnership’s organization and offering costs to itself, its affiliates and independent third-parties and it will contribute the remainder to the partnership in the form of services related to organizing this offering. The managing general partner will receive a credit for these payments and services towards its required capital contribution in each partnership. The managing general partner’s credit for its contribution of services for organization costs will be determined based on generally accepted accounting principles. The definition of organization and offering costs is set forth in the partnership agreement.
2. | Lease Costs. Each partnership’s leases will be contributed to it by the managing general partner. The managing general partner will be credited with a capital contribution for each lease valued at: |
| • | fair market value if the managing general partner has reason to believe that cost is materially more than fair market value. |
The cost of the leases includes a portion of the managing general partner’s reasonable, necessary and actual expenses for geological, geophysical, engineering, drafting, accounting, legal and other like services allocated to the leases in conformity with generally accepted accounting principles and industry standards. Also, the managing general partner has averaged the cost of all of its leases to arrive at the average lease cost per prospect set forth in “Compensation,” which the managing general partner believes is less than fair market value.
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3. | Intangible Drilling Costs. Ninety percent of the subscription proceeds of you and the other investors in a partnership will be used to pay 100% of the intangible drilling costs incurred by that partnership in drilling and completing its wells. |
| • | 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. For example, intangible drilling costs include all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil. Intangible drilling costs also include the expense of plugging and abandoning any well before a completion attempt, and the costs (other than equipment costs and lease acquisition costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs. |
Although subscription proceeds of a partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, 90% of the subscription proceeds of you and the other investors will be used to pay intangible drilling costs regardless of when you subscribe. Also, even if the IRS successfully challenged the managing general partner’s characterization of a portion of these costs as deductible intangible drilling costs, and instead recharacterized the costs as some other item that may not be currently deductible, such as equipment costs and/or lease acquisition costs, this recharacterization by the IRS would have no effect on the allocation and payment of the costs by you and the other investors as intangible drilling costs under the partnership agreement.
The allocation of each partnership’s costs of drilling and completing its wells between intangible drilling costs, as defined in the partnership agreement, and equipment costs, as defined as “tangible costs” in the partnership agreement, will be made by the managing general partner, in its sole discretion, when the wells are drilled.
4. | Equipment Costs. Ten percent of the subscription proceeds of you and the other investors in a partnership will be used to pay a portion of the equipment costs incurred by that partnership. All equipment costs of that partnership’s wells that exceed 10% of the subscription proceeds of you and the other investors in the partnership will be charged to the managing general partner. |
| • | Equipment costs generally means the costs of drilling and completing a well that are not currently deductible and are not lease costs. |
5. | Operating Costs, Direct Costs, Administrative Costs and All Other Costs. Operating costs, direct costs, administrative costs, and all other partnership costs of your partnership not specifically charged under the partnership agreement will be charged between the managing general partner and you and the other investors in the partnership in the same ratio as the related production revenues are being credited. |
| • | These costs generally include all costs of partnership administration and producing and maintaining the partnership’s wells. |
Each well in a partnership will have a different productive life and when a well becomes uneconomic to produce, it will be plugged and abandoned. The costs of plugging and abandoning a well (other than those incurred in connection with drilling a nonproductive well) are shared between the managing general partner and you and the other investors in the same percentage as the related production revenues are being shared. For example, if the investors are receiving 68% of the partnership revenues and the managing general partner is receiving 32% of the partnership revenues, then the cost of plugging and abandoning the wells will be shared in the same percentages. Typically, the managing general partner will apply the salvage value of the equipment towards this obligation. The salvage value of the equipment will be shared between you and the other investors and the managing general partner based on the total amount of the actual equipment costs paid by each. Since the managing general partner in each partnership will have paid a majority of the partnership’s total equipment costs, as compared to the total amount of the partnership’s equipment costs paid by you and the other investors, it will also receive a majority of the salvage value of the equipment. See “Compensation – Drilling Contracts,” for a discussion of the managing general partner’s estimated equipment costs for an average partnership well in the primary drilling areas.
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To cover any shortfall that you and the other investors might incur between your share of the salvage value of the equipment in a well and your share of the plugging and abandoning costs of the well, the managing general partner has the right, beginning one year after each partnership well begins producing, to retain up to $200 per month of the partnership revenues in partnership reserves to cover future plugging and abandonment costs of the well. This $200 also includes the managing general partner’s share of revenues, which will be used exclusively for the managing general partner’s share of the plugging and abandonment costs of the well. To the extent any portion of those reserves ultimately is not required for the plugging and abandonment costs of the well, then it will be returned to the general operating revenues of the partnership.
6. | The Managing General Partner’s Required Capital Contribution. The managing general partner’s aggregate capital contributions to each partnership must not be less than 25% of all capital contributions to that partnership. This includes such items as the managing general partner’s: |
| • | credit for the cost of the leases it contributes to the partnership, or the fair market value of the leases if the managing general partner has a reason to believe that cost is materially more than fair market value; |
| • | credit for the partnership’s organization and offering costs paid or incurred by the managing general partner, including the costs of services contributed by the managing general partner to the partnership as organization costs; and |
| • | share of the partnership’s equipment costs paid by the managing general partner to itself as operator under the drilling and operating agreement. |
The managing general partner’s capital contributions must be paid or made at the time the costs are required to be paid by the partnership, but in any event not later than the end of the year immediately following the year in which the partnership had its final closing.
Revenues
Each partnership’s production revenues from all of its wells will be commingled. Thus, regardless of when you subscribe to a partnership you will share in the production revenues from all of the partnership wells in that partnership on the same basis as the other investors in the partnership in proportion to your number of units.
1. | Proceeds from the Sale of Leases. If a partnership well is sold, a portion of the sales proceeds will be allocated to the partners in the same proportion as their share of the adjusted tax basis of the property. In addition, proceeds will be allocated to the managing general partner to the extent of the pre-contribution appreciation in value of the property, if any. Any excess will be credited as provided in 4, below. |
2. | Interest Proceeds. Interest income earned on your subscription proceeds before your partnership’s final closing will be credited to your account and paid to you not later than the partnership’s first cash distributions from operations. After your partnership’s final closing and until the subscription proceeds are invested in your partnership’s operations, any interest income from temporary investments will be allocated pro rata to you and the other investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, will be credited as provided in 4, below. |
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3. | Equipment Proceeds. Proceeds from the sale or other disposition of equipment will be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged. |
4. | Production Revenues. Subject to the managing general partner’s subordination obligation as described below, the managing general partner and you and the other investors in a partnership will share in all of that partnership’s other revenues, including production revenues, in the same percentage as their respective capital contribution bears to the partnership’s total capital contributions, except that the managing general partner will receive an additional 7% of that partnership’s revenues. |
However, the managing general partner’s total revenue share may not exceed 40% of that partnership’s revenues regardless of the amount of its capital contributions. For example, if the managing general partner contributes the minimum of 25% of the partnership’s total capital contributions and the investors contribute 75% of the partnership’s total capital contributions, then the managing general partner will receive 32% of the partnership revenues and the investors will receive 68% of the partnership revenues. On the other hand, if the managing general partner contributes 35% of the partnership’s total capital contributions and the investors contribute 65% of the partnership’s total capital contributions, then the managing general partner will receive 40% of the partnership revenues, not 42%, because its revenue share cannot exceed 40% of partnership revenues, and the investors will receive 60% of partnership revenues. See “Compensation – Natural Gas and Oil Revenues” for a graphic presentation of these amounts.
Subordination of Portion of Managing General Partner’s Net Revenue Share
Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with that partnership’s first cash distributions from operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share, as managing general partner, of partnership net production revenues, which will be up to between 16% and 20% of the total partnership net production revenues, depending on the amount of its capital contributions, during this subordination period.
| • | Partnership net production revenues means gross revenues after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated. |
Each partnership’s 60-month subordination period will begin with that partnership’s first cash distribution from operations to you and the other investors. The estimated maximum time from the closing for a partnership to begin distributions is eight months from the closing as discussed in “Investment Objectives.” Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from that partnership exceed the 10% return of capital described above. The specific formula for determining subordination distributions is set forth in Section 5.01(b)(4)(a) of the partnership agreement.
The managing general partner anticipates that you will benefit from the subordination if the price of natural gas and oil received by the partnership and/or the results of the partnership’s drilling activities, such as the volume of natural gas and oil produced from the partnership’s wells, are unable to provide the required return of capital. However, if the wells produce small natural gas and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow may be very small and you may not receive the 10% return of capital for each of the first five years beginning with the partnership’s first cash distribution from operations.
As of September 15, 2006, the managing general partner was not subordinating any of its partnership net production revenues in the 16 limited partnerships that currently have the subordination feature in effect. Since 1993 the managing general partner has had the same or a similar subordination feature in 34 of its partnerships and from time to time it has subordinated its partnership net production revenues in 16 of those partnerships. The managing general partner is entitled to recoup those subordination distributions during the respective subordination period of those previous partnerships to the extent cash distributions of those previous partnerships to their respective investors would exceed the specified return to the investors.
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Example of Net Revenue Sharing During a Subordination Period.
Entity | | Percentage of
Partnership
Capital
Contributions (1) | | Percentage of
Partnership Net
Revenues Without
Subordination (1) | | Maximum Amount of
Managing General Partner’s Share of
Partnership Net
Revenues Available
for Subordination (2) | | Net Revenues to
Managing General
Partner and Investors if
Maximum Amount of
Managing General
Partner’s Share of
Partnership Net Revenues
is Subordinated (1)(2) | |
| |
| |
| |
| |
| |
Managing General Partner | | 25 | % | 32 | % | 16 | % | 16 | % |
Investors | | 75 | % | 68 | % | | | 84 | % |
(1) | These percentages are for illustration purposes only and assume the managing general partner’s minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner’s total revenue share may not exceed 40% of partnership revenues regardless of the amount of its capital contribution. |
(2) | Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% of capital, based on a subscription price of $10,000 per unit, regardless of the actual subscription price you paid for your units, in each of the first five 12-month periods beginning with the partnership’s first cash distributions from operations. To help achieve this investment feature of a 10% return of capital for each of the first five 12-month periods, the managing general partner will subordinate up to 50% of its share of partnership net production revenues, which will be up to between 16% and 20% of the total partnership net production revenues, depending on the amount of its capital contributions, during this subordination period. |
Example of Net Revenue Sharing After the End of a Subordination Period.
Entity | | Percentage of
Partnership
Capital
Contributions (1) | | Percentage of
Partnership Net
Revenues Without
Subordination (1) | | Maximum Amount of
Managing General
Partner’s Share of
Partnership Net
Revenues Available
for Subordination | | Net Revenues to Managing
General Partner and
Investors When None of
Managing General
Partner’s Share of
Partnership Net Revenues
is Subordinated (1) | |
| |
| |
| |
| |
| |
Managing General Partner | | 25 | % | 32 | % | 0 | % | 32 | % |
Investors | | 75 | % | 68 | % | | | 68 | % |
(1) | These percentages are for illustration purposes only and assume the managing general partner’s minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner’s total revenue share may not exceed 40% of partnership revenues regardless of the amount of its capital contribution. |
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Table of Participation in Costs and Revenues
The following table sets forth certain partnership costs and revenues charged and credited between the managing general partner and you and the other investors in each partnership, after deducting from the partnership’s gross revenues, the landowner royalties and any other lease burdens.
| | Managing
General
Partner | | Investors | |
| |
| |
| |
Partnership Costs | | | | | |
Organization and offering costs | | 100 | % | 0 | % |
Lease costs | | 100 | % | 0 | % |
Intangible drilling costs (1) | | 0 | % | 100 | % |
Equipment costs | | | (2) | | (2) |
Operating costs, administrative costs, direct costs, and all other costs | | | (3) | | (3) |
| | | | | |
Partnership Revenues | | | | | |
Interest income | | | (4) | | (4) |
Equipment proceeds | | | (2) | | (2) |
All other revenues including production revenues | | | (5)(6) | | (5)(6) |
| | | | | |
Participation in Deductions and Credits | | | | | |
Intangible drilling costs | | 0 | % | 100 | % |
Depreciation | | | (2) | | (2) |
Percentage depletion allowance | | | (5)(6)(7) | | (5)(6)(7) |
Marginal well production credits | | | (5)(6)(7) | | (5)(6)(7) |
(1) | Ninety percent of the subscription proceeds of you and the other investors in a partnership will be used to pay 100% of the intangible drilling costs incurred by that partnership in drilling and completing its wells. |
(2) | Ten percent of the subscription proceeds of you and the other investors in a partnership will be used to pay a portion of the equipment costs incurred by that partnership in drilling and completing its wells. All equipment costs in excess of 10% of that partnership’s subscription proceeds will be paid by the managing general partner. Thus, the managing general partner will pay the majority of each partnership’s equipment costs. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. Thus, the managing general partner will receive the majority of any equipment proceeds. |
(3) | These costs, which also include plugging and abandonment costs of the wells after the wells have been drilled, produced, and depleted, will be charged to the parties in the same ratio as the related production revenues are being credited. |
(4) | Interest earned on your subscription proceeds before a partnership’s final closing will be credited to your account and paid to you not later than the partnership’s first cash distributions from operations. After the partnership’s final closing and until the partnership’s subscription proceeds are invested in its operations, any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income in the partnership, including interest earned on the deposit of operating revenues, will be credited as production revenues are credited. |
(5) | In each partnership the managing general partner and you and the other investors will share in all of the partnership’s other revenues in the same percentage that their respective capital contributions bear to the partnership’s total capital contributions, except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner’s total revenue share in a partnership may not exceed 40% of partnership revenues. |
(6) | If a portion of the managing general partner’s partnership net production revenues is subordinated, then the actual allocation of partnership revenues between the managing general partner and you and the other investors will vary from the allocation described in (5) above. |
(7) | The percentage depletion allowances and any marginal well production credits will be credited between the managing general partner and you and the other investors in the same percentages as the production revenues are being credited. |
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Allocation and Adjustment Among Investors
The investors’ share as a group of each partnership’s revenues, gains, income, costs, marginal well production credits, expenses, losses, and other charges and liabilities generally will be charged and credited among you and the other investors in that partnership in accordance with the ratio that your respective number of units bears to the number of units held by all investors as a group in that partnership, based on a subscription price of $10,000 per unit regardless of the actual subscription price you paid for your units. These allocations will take into account any investor general partner’s status as a defaulting investor general partner. Certain investors, however, will pay a discounted subscription price for their units as described in “Plan of Distribution.” Thus, intangible drilling costs and the investors’ share of the equipment costs of drilling and completing the partnership’s wells will be charged among you and the other investors in a partnership as set forth above, except that these allocations (i.e., intangible drilling costs and equipment costs) will be based on the respective subscription amount paid by you and the other investors for your respective units as set forth on your respective subscription agreements, rather than a subscription price of $10,000 per unit for all of the units.
Distributions
The managing general partner will review each partnership’s accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any, taking into account its subordination obligation discussed above in “– Subordination of Portion of Managing General Partner’s Net Revenue Share.” Your partnership will distribute funds to you and the other investors that the managing general partner, in its sole discretion, does not believe are necessary for the partnership to retain. Distributions may be reduced or deferred to the extent partnership revenues are used for any of the following:
| • | repayment of partnership borrowings; |
| • | remedial work to improve a well’s producing capability; |
| • | compensation and fees to the managing general partner as described in “Risk Factors – Risks Related to an Investment In a Partnership – Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership’s Activities Will Reduce Cash Distributions”; |
| • | direct costs and general and administrative expenses of the partnership; |
| • | reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or |
| • | indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership’s activities. |
Also, funds will not be advanced or borrowed by a partnership for the purpose of making distributions to you and the other investors if the amount advanced or borrowed would exceed the partnership’s accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Any cash distributions from a partnership to the managing general partner will be made only in conjunction with distributions to you and the other investors in that partnership and only out of funds properly allocated to the managing general partner’s account.
Liquidation
Each partnership will continue for 50 years unless it is terminated earlier by a final terminating event as described below, or an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if a partnership terminates on an event which causes a dissolution of the partnership under state law and it is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will a partnership be liquidated. A final terminating event is any of the following:
| • | the election to terminate the partnership by the managing general partner or the affirmative vote of investors whose units equal a majority of the total units; |
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| • | the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code because no part of its business is being carried on; or |
| • | the partnership ceases to be a going concern. |
On the partnership’s liquidation you will receive your interest in the partnership to which you subscribed. Generally, your interest in the partnership means an undivided interest in the partnership’s assets, after payments to the partnership’s creditors, in the ratio that your positive capital account bears to the positive capital accounts of all of the partners in the partnership (including the managing general partner) until all of the capital accounts have been reduced to zero. Thereafter, your interest in the remaining partnership assets will equal your interest in the related partnership revenues.
Any in-kind property distributions to you from the partnership in which you invest must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told the risks associated with the direct ownership of the property or unless there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of the partnership’s properties. If the managing general partner has not received your written consent to a proposed in-kind property distribution within 30 days after it is mailed, then it will be presumed that you have not consented. The 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 the managing general partner. Also, if the partnership is liquidated the managing general partner will be repaid any debts owed to it by the partnership before there are any payments to you and the other investors in that partnership.
CONFLICTS OF INTEREST
In General
Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry investors because the transactions are entered into without arms’ length negotiation. Your interests and those of the managing general partner and its affiliates may be inconsistent in some respects or in certain instances, and the managing general partner’s actions may not be the most advantageous to you. The following discussion describes all material possible conflicts of interest that may arise for the managing general partner and its affiliates in the course of each partnership. For some of the conflicts of interest, but not all, there are certain limitations on the managing general partner that are designed to reduce, but will not eliminate, the conflicts. Other than these limitations the managing general partner has no procedures to resolve a conflict of interest and under the terms of the partnership agreement the managing general partner may resolve the conflict of interest in its sole discretion and best interest.
Further, the managing general partner depends on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for management and administrative functions and financing for capital expenditures. Neither the partnership agreement nor any other agreement requires Atlas America or Atlas Energy Resources, LLC to pursue a future business strategy that favors the partnerships. The directors and officers of Atlas America and Atlas Energy Resources, LLC and their affiliates have a fiduciary duty to make decisions in the best interests of their respective stockholders. Because the managing general partner is allowed to take into account the interests of parties other than the partnerships, such as Atlas America, Atlas Energy Resources, LLC, and their affiliates in resolving partnership conflicts of interest, this has the effect of creating a conflict of interest. However, this conflict of interest is not allowed to limit the managing general partner’s fiduciary duty to the partnerships.
The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates.
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Conflicts Regarding Transactions with the Managing General Partner and its Affiliates
Although the managing general partner believes that the compensation and reimbursement that it and its affiliates will receive in connection with each partnership are reasonable, the compensation has been determined solely by the managing general partner and did not result from negotiations with any unaffiliated third-party dealing at arms’ length. The managing general partner and its affiliates will receive compensation and reimbursement from each partnership for their services in drilling, completing, and operating that partnership’s wells under the drilling and operating agreement and will receive the other fees described in “Compensation” regardless of the success of that partnership’s wells. The managing general partner and its affiliates providing the services or equipment can be expected to profit from the transactions, and it is usually in the managing general partner’s best interest to enter into contracts with itself and its affiliates, rather than unaffiliated third-parties even if the contract terms, skill, and experience, offered by the unaffiliated third-parties are comparable.
When the managing general partner or any affiliate provides services or equipment to a partnership the partnership agreement provides that their fees must be competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. Also, before the managing general partner or any affiliate may receive competitive fees for providing services or equipment to a partnership they must be engaged, independently of the partnership and as an ordinary and ongoing business, in rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the managing general partner or an affiliate has an interest. If the managing general partner or the affiliate is not engaged in such a business, then the compensation must be the lesser of its cost or the competitive rate that could be obtained in the area.
Any services not otherwise described in this prospectus or the partnership agreement for which the managing general partner or an affiliate is to be compensated by a partnership must be:
| • | set forth in a written contract that describes the services to be rendered and the compensation to be paid; and |
| • | cancelable without penalty on 60 days written notice by investors whose units equal a majority of the total units. |
The compensation paid by the partnership to the managing general partner or its affiliates for additional services to the partnership under these contracts, if any, will be reported to you in your partnership’s annual and semiannual reports, and a copy of the contract will be provided to you on request.
There is also a conflict of interest concerning the purchase price if the managing general partner or an affiliate purchases a property from a partnership, which they may do in certain limited circumstances as described in “– Conflicts Involving the Acquisition of Leases – (6) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner,” below.
Conflict Regarding the Drilling and Operating Agreement
The managing general partner anticipates that all of the wells to be drilled by each partnership will be drilled and operated under the drilling and operating agreement. This creates a continuing conflict of interest because the managing general partner must monitor and enforce, on behalf of each partnership, its own compliance, as operator with the drilling and operating agreement and as managing general partner with the partnership agreement, and the compliance of its affiliate, Atlas Pipeline Partners, with the gas gathering agreement.
Conflicts Regarding Sharing of Costs and Revenues
The managing general partner will receive a percentage of partnership revenues that is greater than the percentage of partnership costs that it pays. This sharing arrangement may create a conflict of interest between the managing general partner and you and the other investors in a partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells.
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In addition, the allocation of all of the intangible drilling costs to you and the other investors and the majority of the equipment costs to the managing general partner creates a conflict of interest between the managing general partner and you and the other investors concerning whether to complete a well. For example, the completion of a marginally productive well might prove beneficial to you and the other investors, but not to the managing general partner. When a completion decision is made, you and the other investors will have already paid the majority of your costs so you will want to pay your share of the additional costs to complete the well (i.e., 10% of the additional equipment costs to complete the well) if there is a reasonable opportunity to recoup your share of the completion costs plus any portion of the costs of the well paid by you before the completion attempt.
On the other hand, the managing general partner will have paid only a portion of its costs before this time, and it will want to pay its additional equipment costs to complete the well only if it is reasonably certain of recouping its share of the completion costs and making a profit. However, based on its past experience the managing general partner anticipates that most of the wells in the primary areas will have to be completed before it can determine the well’s productivity, which would eliminate this potential conflict of interest. In any event, the managing general partner will not cause any well to be plugged and abandoned without a completion attempt unless it makes the decision in accordance with generally accepted oil and gas field practices in the geographic area of the well location.
Conflicts Regarding Tax Matters Partner
The managing general partner will serve as each partnership’s tax matters partner and represent the partnership before the IRS. The managing general partner will have broad authority to act on behalf of you and the other investors in the partnership in any administrative or judicial proceeding involving the IRS, and this authority may involve conflicts of interest. For example, potential conflicts include:
| • | whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, that would decrease: |
| • | the amount of a partnership’s deduction for intangible drilling costs, which is allocated 100% to you and the other investors in the partnership; or |
| • | the amount of the managing general partner’s depreciation deductions, or the credit to its capital account for contributing the leases to a partnership which would also decrease the managing general partner’s liquidation interest in the partnership; or |
| • | the amount charged to a partnership by the managing general partner as reimbursement for expenses incurred by the managing general partner in its role as the tax matters partner. |
Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates
The managing general partner will be required to devote to each partnership the time and attention that it considers necessary for the proper management of the partnership’s activities. However, the managing general partner has sponsored and continues to manage other natural gas and oil drilling partnerships, which may be concurrent, and it will engage in unrelated business activities, either for its own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which it has an interest. This creates a continuing conflict of interest in allocating management time, services, and other activities among the partnerships in this program and the managing general partner’s other activities.
The managing general partner will determine the allocation of its management time, services, and other functions on an as-needed basis consistent with its fiduciary duties among the partnerships in this program and its other activities. However, the managing general partner depends on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for management and administrative functions and financing for capital expenditures as described in “Management – Transactions with Management and Affiliates.” Thus, the competition for the time and services of the managing general partner and its affiliates could result in insufficient attention to the management and operation of the partnerships.
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Subject to its fiduciary duties, the managing general partner will not be restricted from participating in other businesses or activities, even if these other businesses or activities compete with a partnership’s activities and operate in the same areas as a partnership. However, the managing general partner and its affiliates may pursue business opportunities that are consistent with a partnership’s investment objectives for their own account only after they have determined that the opportunity either:
| • | cannot be pursued by the partnership because of insufficient funds; or |
| • | it is not appropriate for the partnership under the existing circumstances. |
Conflicts Involving the Acquisition of Leases
The managing general partner will select, in its sole discretion, the wells to be drilled by each partnership. Conflicts of interest may arise concerning which wells will be drilled by each partnership in this program and which wells will be drilled by the managing general partner’s and its affiliates’ other affiliated partnerships or third-party programs in which they serve as driller/operator. It may be in the managing general partner’s or its affiliates’ advantage to have a partnership in this program bear the costs and risks of drilling a particular well rather than another affiliate. These potential conflicts of interest will be increased if the managing general partner organizes and allocates wells to more than one partnership at a time. To lessen this conflict of interest the managing general partner generally takes a similar interest in the other partnerships when it serves as managing general partner and/or driller/operator of the other partnerships. Also, as discussed in “Proposed Activities,” the managing general partner has a drilling commitment with Knox Energy for the drilling of 300 wells, which creates a conflict of interest in deciding whether the managing general partner will select wells for each partnership to drill in the areas that will help the managing general partner satisfy this drilling commitment.
When the managing general partner must provide prospects to two or more partnerships at the same time it will attempt to treat each partnership fairly on a basis consistent with:
| • | the funds available to the partnerships; and |
| • | the time limitations on the investment of funds for the partnerships. |
The partnership agreement gives the managing general partner the authority to cause each partnership in this program to acquire undivided interests in natural gas and oil properties, and to participate with other parties, including other drilling programs previously or subsequently conducted by the managing general partner or its affiliates, in the conduct of its drilling operations on those properties. If conflicts between the interest of a partnership in this program and other drilling partnerships do arise, then the managing general partner may be unable to resolve those conflicts to the maximum advantage of a partnership in this program because the managing general partner must deal fairly with the investors in all of its drilling partnerships.
In addition, subject to the restrictions set forth below, the managing general partner decides which prospects and what interest in the prospects to transfer to a partnership. This will result in a subsequent partnership sponsored by the managing general partner benefiting from knowledge gained through a prior partnership’s drilling experience in an area and acquiring a prospect adjacent to the prior partnership’s prospect. In this regard, as drilling progresses, reserves from newly completed wells are reclassified from the proved undeveloped to the proved developed category and additional adjacent locations are added to proved undeveloped reserves.
No procedures, other than the guidelines set forth below and in “– Procedures to Reduce Conflicts of Interest,” have been established by the managing general partner to resolve any conflicts that may arise. The partnership agreement provides that the managing general partner and its affiliates will abide by the guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and (9) there is an exception in the partnership agreement for another program in which the interest of the managing general partner is substantially similar to or less than its interest in the partnerships.
(1) | Transfers at Cost. All leases will be acquired by each partnership from the managing general partner and credited towards its required capital contribution to the partnership at the cost of the lease, unless the managing general partner has a reason to believe that cost is materially more than the fair market value of the property. If the managing general partner believes that cost is materially more than fair market value, then the managing general partner’s credit for the contribution must be at a price not in excess of the fair market value. See “Compensation – Lease Costs” regarding the managing general partner averaging its lease costs and “Participation in Costs and Revenues – Costs – Lease Costs.” |
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| | • | A determination of fair market value must be supported by an appraisal from an independent expert and maintained in the partnership’s records for at least six years. |
(2) | Equal Proportionate Interest. When the managing general partner sells or transfers an oil and gas interest to a partnership, it must, at the same time, sell or transfer to the partnership an equal proportionate interest in all of its other property in the same prospect. |
| | • | The term “prospect” generally means an area which is believed to contain commercially productive quantities of natural gas or oil. |
However, a prospect will be limited to the drilling or spacing unit on which one well will be drilled if the following two conditions are met:
| • | the well is being drilled to a geological feature which contains proved reserves as defined below; and |
| • | the drilling or spacing unit protects against drainage. |
The managing general partner believes that for a prospect located in the primary drilling areas as described in “Proposed Activities – Primary Areas of Operations,” a prospect will consist of the drilling and spacing unit because it will meet the test in the preceding sentence.
| • | Proved reserves, generally, are the estimated quantities of natural gas and oil which have been demonstrated to be recoverable in future years with reasonable certainty under existing economic and operating conditions. Proved reserves include proved undeveloped reserves which generally are reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion or from new wells on undrilled acreage. Reserves on undrilled acreage will be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. |
In the primary areas the managing general partner anticipates that the drilling of these wells by each partnership may provide the managing general partner with offset sites by allowing it to determine, at the partnership’s expense, the value of adjacent acreage in which the partnership would not have any interest. The managing general partner owns acreage throughout the primary areas where each partnership’s wells will be situated. To lessen this conflict of interest, for five years the managing general partner may not drill any well:
| • | to the Clinton/Medina geologic formation, if the well would be within 1,650 feet of an existing partnership well in Pennsylvania or within 1,000 feet of an existing partnership well in Ohio; or |
| • | to the Mississippian/Upper Devonian Sandstone reservoirs in Fayette, Greene and Westmoreland Counties, Pennsylvania, if the well would be within at least 1,000 feet from a producing well, although a partnership may drill a new well or re-enter an existing well that is closer than 1,000 feet to a plugged and abandoned well. |
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If a partnership abandons its interest in a well, then the restrictions described above will continue for one year following the abandonment. There are no similar prohibitions for a partnership’s other primary drilling area, although the managing general partner believes that none of the prospects transferred to a partnership will result in drainage from the surrounding wells.
(3) | Subsequently Enlarging Prospect. In areas where the prospect is not limited to the drilling or spacing unit and the area constituting a partnership’s prospect is subsequently enlarged based on geological information, which is later acquired, then there is the following special provision: |
| • | if the prospect is enlarged to cover any area where the managing general partner owns a separate property interest and the partnership activities were material in establishing the existence of proved undeveloped reserves which are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold to the partnership in accordance with (1), (2) and (4). |
(4) | Transfer of Less than the Managing General Partner’s and its Affiliates’ Entire Interest. If the managing general partner sells or transfers to a partnership less than all of its ownership in any prospect, then it must comply with the following conditions: |
| • | the retained interest must be a proportionate working interest; |
| • | the managing general partner’s obligations and the partnership’s obligations must be substantially the same after the sale of the interest by the managing general partner or its affiliates; and |
| • | the managing general partner’s revenue interest must not exceed the amount proportionate to its retained working interest. |
For example, if the managing general partner transfers 50% of its working interest in a prospect to a partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the managing general partner’s retained working interest as a part of the transfer. This limitation does not prevent the managing general partner and its affiliates from subsequently dealing with their retained working interest as they may choose with unaffiliated parties or affiliated partnerships. For example, the managing general partner may sell its retained working interest to a third-party for a profit.
(5) | Limitations on Activities of the Managing General Partner and its Affiliates on Leases Acquired by a Partnership. For a five year period after the final closing of a partnership, if the managing general partner proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership’s interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply: |
| • | if the managing general partner does not currently own property in the prospect separately from the partnership, then the managing general partner may not buy an interest in the prospect; and |
| • | if the managing general partner currently owns a proportionate interest in the prospect separately from the partnership, then the interest to be acquired must be divided in the same proportion between the managing general partner and the partnership as the other property in the prospect. However, if the partnership does not have the cash or financing to buy the additional interest, then the managing general partner is also prohibited from buying the additional interest. |
(6) | Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner. The managing general partner and its affiliates, other than an affiliated partnership as set forth in (7) below, may not purchase undeveloped leases or receive a farmout from a partnership other than at the higher of cost or fair market value. Farmouts to the managing general partner and its affiliates also must comply with the conditions set forth in (9) below. |
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The managing general partner and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from a partnership unless:
| • | the sale is in connection with the liquidation of the partnership; or |
| • | the managing general partner’s well supervision fees under the drilling and operating agreement for the well have exceeded the net revenues of the well, determined without regard to the managing general partner’s well supervision fees for the well, for a period of at least three consecutive months. |
In both cases, the sale must be at fair market value supported by an appraisal of an independent expert selected by the managing general partner. The appraisal of the property must be maintained in the partnership’s records for at least six years.
(7) | Transfer of Leases Between Affiliated Limited Partnerships. The transfer of an undeveloped lease from a partnership to an affiliated drilling limited partnership must be made at fair market value if the undeveloped lease has been held by the partnership for more than two years. Otherwise, the transfer may be made at cost if the managing general partner deems it to be in the best interest of the partnership. |
An affiliated income program may purchase a producing natural gas and oil property from a partnership at any time at:
| • | fair market value as supported by an appraisal from an independent expert if the property has been held by the partnership for more than six months or there have been significant expenditures made in connection with the property; or |
| • | cost as adjusted for intervening operations if the managing general partner deems it to be in the best interest of the partnership. |
However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that:
| • | the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and |
| • | the compensation arrangement or any other interest or right of either the managing general partner or its affiliates is the same in each affiliated partnership or if different, the aggregate compensation of the managing general partner or the affiliate is reduced to reflect the lower compensation arrangement. |
(8) | Leases Will Be Acquired Only for Stated Purpose of the Partnership. Each partnership must acquire only leases that are reasonably expected to meet the stated purposes of the partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the partnership’s best interest. |
(9) | Farmout. The managing general partner may not assign the working interest in a prospect to a partnership for the purpose of a subsequent farmout, sale or other disposition, nor may the managing general partner enter into a farmout to avoid paying its share of the costs related to drilling a well on an undeveloped lease. However, the managing general partner’s decision with respect to making a farmout and the terms of a farmout from a partnership involve conflicts of interest since the managing general partner may benefit from cost savings and reduction of its risk. |
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The partnership may farmout an undeveloped lease or well activity to the managing general partner, its affiliates or an unaffiliated third-party only if the managing general partner, exercising the standard of a prudent operator, determines that:
| • | the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing; |
| • | drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership; |
| • | the leases or well activity have been downgraded by events occurring after assignment to the partnership so that development of the leases or well activity would not be desirable; or |
| • | the best interests of the partnership would be served. |
If the partnership farmouts a lease or well activity, the managing general partner must retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. However, if the farmout is made to the managing general partner or its affiliates there is a conflict of interest since the managing general partner will represent both the partnership and itself or an affiliate. Although the conflict of interest may be resolved to the managing general partner’s benefit, the managing general partner must still retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices.
Conflicts Regarding Order of Pipeline Construction and Gathering Fees
There are conflicts between you and the managing general partner and its affiliates, because the managing general partner must monitor and enforce on behalf of the partnerships the compliance of its affiliate, Atlas Pipeline Partners, with the gas gathering agreement. Also, the managing general partner may choose well locations for the partnerships that are situated near Atlas Pipeline Partners’ gathering system which would benefit the managing general partner’s indirect parent company, Atlas America, by providing more gathering fees to Atlas Pipeline Partners, even if there are other well locations available in the same area or other areas which offer the partnerships a greater potential return. (See “Management – Organizational Diagram and Security Ownership of Beneficial Owners.”) However, the managing general partner believes this conflict of interest is substantially reduced because the managing general partner expects to make the largest single capital contribution in each partnership as explained in “Capitalization and Source of Funds and Use of Proceeds.”
In addition, Atlas America or an affiliate will operate the Atlas Pipeline Partners gathering system. Thus, the expansion of the Atlas Pipeline Partners gathering system will be within the control of the managing general partner’s affiliate, which the managing general partner believes will attempt to expand the Atlas Pipeline Partners gathering system to those areas with the greatest number of wells with the greatest potential reserves. However, Atlas Pipeline Holdings, L.P., a wholly-owned subsidiary of Atlas America, recently completed an initial public offering of a minority interest in its units and, as a public company, may be more susceptible to a change of control. (See “Risk Factors – Risks Related to the Partnerships’ Oil and Gas Operations – Adverse Events in Marketing a Partnership’s Natural Gas Could Reduce Partnership Distributions.”)
Further, certain of the managing general partner’s affiliates, including Atlas America and/or Atlas Energy Resources, LLC, are obligated through their agreement with Atlas Pipeline Partners to pay the difference between the amount a partnership pays for gathering fees to the managing general partner as set forth in “Compensation – Gathering Fees,” and the greater of $.35 per mcf or 16% of the gross sales price for the natural gas. This creates a conflict of interest between the managing general partner and a partnership because the managing general partner has an economic incentive to increase the amount of gathering fees paid by the partnership so as to reduce the amount paid by Atlas America and/or Atlas Energy Resources, LLC to Atlas Pipeline Partners, but any increase cannot exceed a competitive rate. Further, if Atlas Pipeline Partners GP, LLC were removed as general partner of Atlas Pipeline Partners without cause and without its consent, this could create further pressure to increase the amount of gathering fees required to be paid by a partnership for natural gas transported through Atlas Pipeline Partners’ gathering system. This could happen because Atlas Pipeline Partners GP, LLC would no longer receive revenues from Atlas Pipeline Partners, but Atlas America and its affiliates would still be obligated to pay the difference between the amount of gathering fees set forth in the master natural gas gathering agreement, as described above, and the amount of gathering fees paid by a partnership, other than with respect to new wells drilled by the partnership after the removal of Atlas Pipeline Partners GP, LLC as general partner of Atlas Pipeline Partners, if any. Thus, the managing general partner and its affiliates would have a further economic incentive to increase the gathering fees. Any increase in the gathering fees that a partnership pays would reduce your cash distributions from the partnership. However, the gathering fees paid to the managing general partner may not exceed competitive rates.
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Conflicts Between Investors and the Managing General Partner as an Investor
The managing general partner, its officers, directors, and its affiliates may subscribe for units in each partnership and the subscription price of their units will be reduced by 10% as described in “Plan of Distribution.” Even though they pay a reduced price for their units, these investors generally will:
| • | share in the partnership’s costs, revenues, and distributions on the same basis as the other investors as described in “Participation in Costs and Revenues”; and |
| • | have the same voting rights, except as discussed below. |
Any subscription for units by the managing general partner, its officers, directors, or affiliates in the partnership in which you invest will dilute the voting rights of you and the other investors and there may be a conflict with respect to certain matters. The managing general partner and its officers, directors and affiliates, however, are prohibited from voting with respect to certain matters as described in “Summary of Partnership Agreement – Voting Rights.”
Lack of Independent Underwriter and Due Diligence Investigation
The terms of this offering, the partnership agreement, and the drilling and operating agreement were determined by the managing general partner without arms’ length negotiations. You and the other investors have not been separately represented by legal counsel, who might have negotiated more favorable terms for you and the other investors in this offering and the agreements.
Also, there was not an extensive in-depth “due diligence” investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Although Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager of this offering and will receive reimbursement of bona fide due diligence expenses for certain due diligence investigations conducted by the selling agents, all of which will be reallowed by Anthem Securities to the selling agents, its due diligence examination concerning this offering cannot be considered to be independent or as comprehensive as a due diligence examination that would have been conducted by an independent underwriter.
Conflicts Concerning Legal Counsel
The managing general partner anticipates that its legal counsel will also serve as legal counsel to each partnership and that this dual representation will continue in the future. However, if a future dispute arises between the managing general partner and you and the other investors in a partnership, then the managing general partner will cause you and the other investors to retain separate counsel. Also, if counsel advises the managing general partner that counsel reasonably believes its representation of a partnership will be adversely affected by its responsibilities to the managing general partner, then the managing general partner will cause you and the other investors in a partnership to retain separate counsel.
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Conflicts Regarding Presentment Feature
You and the other investors in a partnership have the right to present your units in the partnership to the managing general partner for purchase beginning with the fifth calendar year after the end of the calendar year in which your partnership closes. This creates the following conflicts of interest between you and the managing general partner.
| • | The managing general partner may suspend the presentment feature if it does not have the necessary cash flow or it cannot borrow funds for this purpose on terms which it deems reasonable. Both of these determinations are subjective and will be made in the managing general partner’s sole discretion. |
| • | The managing general partner will also determine the purchase price based on a reserve report that it prepares and is reviewed by an independent expert that it chooses. The formula for arriving at the purchase price has many subjective determinations that are within the discretion of the managing general partner. |
Conflicts Regarding Managing General Partner Withdrawing or Assigning an Interest
A conflict of interest is created with you and the other investors by the managing general partner’s right to do any of the following:
| • | mortgage its managing general partner interest in each partnership; |
| • | withdraw an interest in each partnership’s wells equal to or less than its revenue interest to be used as collateral for a loan to the managing general partner; or |
| • | assign, subject to the managing general partner’s subordination obligation, its managing general partner interest in each partnership to its affiliates which also may mortgage the interests as collateral for their loans, if any. |
If the managing general partner assigned a portion or all, of its managing general partner interest in a partnership to an affiliate, the amount of partnership net production revenues available to the managing general partner or an affiliated assignee for their respective subordination obligations to you and the other investors could be reduced or eliminated if there was a default under a loan to the managing general partner or the affiliated assignee. Also, under certain circumstances, if the managing general partner or an affiliated assignee if a portion or all, of the managing general partner’s managing general partner interest in a partnership was assigned by the managing general partner to an affiliate as discussed above, made a subordination distribution to you and the other investors after a default to its lenders, then the lenders may be able to recoup that subordination distribution from you and the other investors.
Procedures to Reduce Conflicts of Interest
In addition to the procedures set forth in “– Conflicts Involving the Acquisition of Leases,” the managing general partner and its affiliates will comply with the following procedures in the partnership agreement to reduce some of the conflicts of interest with you and the other investors. The managing general partner does not have any other conflict of interest resolution procedures. Thus, conflicts of interest between the managing general partner and you and the other investors may not necessarily be resolved in your best interests. However, the managing general partner believes that its significant capital contribution to each partnership will reduce the conflicts of interest.
(1) | Fair and Reasonable. The managing general partner may not sell, transfer, or convey any property to, or purchase any property from, a partnership except pursuant to transactions that are fair and reasonable; nor take any action with respect to the assets or property of a partnership which does not primarily benefit the partnership. |
(2) | No Compensating Balances. The managing general partner may not use a partnership’s funds as a compensating balance for its own benefit. Thus, a partnership’s funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the managing general partner for its own corporate purposes. |
(3) | Future Production. The managing general partner may not commit the future production of a partnership well exclusively for the managing general partner’s own benefit. |
(4) | Disclosure. Any agreement or arrangement that binds a partnership must be fully disclosed in this prospectus. |
(5) | No Loans from a Partnership. A partnership may not loan money to the managing general partner. |
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(6) | No Rebates. The managing general partner may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups. |
(7) | Sale of Assets. The sale of all or substantially all of the assets of a partnership may only be made with the consent of investors whose units equal a majority of the total units. |
(8) | Participation in Other Partnerships. If a partnership participates in other partnerships or joint ventures, then the terms of the arrangements must not circumvent any of the requirements contained in the partnership agreement, including the following: |
| • | there may be no duplication or increase in organization and offering expenses, the managing general partner’s compensation, partnership expenses, or other fees and costs; |
| • | there may be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and |
| • | there may be no diminishment in your voting rights. |
(9) | Investments. A partnership’s funds may not be invested in the securities of another person except in the following instances: |
| • | investments in working interests made in the ordinary course of the partnership’s business; |
| • | temporary investments in income producing short-term highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills; |
| • | multi-tier arrangements meeting the requirements of (8) above; |
| • | investments involving less than 5% of the total subscription proceeds of the partnership that are a necessary and incidental part of a property acquisition transaction; and |
| • | investments in entities established solely to limit the partnership’s liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses are prohibited. |
(10) | Safekeeping of Funds. The managing general partner may not employ, or permit another to employ, the funds or assets of a partnership in any manner except for the exclusive benefit of the partnership. The managing general partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of each partnership whether or not in the managing general partner’s possession or control. |
(11) | Advance Payments. Advance payments by each partnership to the managing general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs and for a business purpose. |
Policy Regarding Roll-Ups
It is possible at some indeterminate time in the future that each partnership may become involved in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger, conversion, or consolidation of a partnership with or into another partnership, corporation or other entity, and the issuance of securities by the roll-up entity to you and the other investors. A roll-up will also include any change in the rights, preferences, and privileges of you and the other investors in the partnership. These changes could include the following:
| • | increasing the compensation of the managing general partner; |
| • | amending your voting rights; |
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| • | listing the units on a national securities exchange or on NASDAQ; |
| • | changing the partnership’s fundamental investment objectives; or |
| • | materially altering the partnership’s duration. |
If a roll-up should occur in the future, the partnership agreement provides various policies which include the following:
| • | an independent expert must appraise all partnership assets as discussed in §4.03(d)(16)(a) of the partnership agreement, and you must receive a summary of the appraisal in connection with a proposed roll-up; |
| • | if you vote “no” on the roll-up proposal, then you will be offered a choice of: |
| • | accepting the securities of the roll-up entity; or |
| • | remaining a partner in the partnership and preserving your units in the partnership on the same terms and conditions as existed previously; or |
| • | receiving cash in an amount equal to your pro-rata share of the appraised value of the partnership’s net assets; and |
| • | the partnership will not participate in a proposed roll-up: |
| • | unless approved by investors whose units equal 66% of the total units; |
| • | which would result in the diminishment of your voting rights under the roll-up entity’s chartering agreement; |
| • | which includes provisions which would operate to materially impede or frustrate the accumulation of shares by you of the securities of the roll-up entity; |
| • | in which your right of access to the records of the roll-up entity would be less than those provided by the partnership agreement; or |
| • | in which any of the transaction costs would be borne by the partnership if the proposed roll-up is not approved by investors whose units equal 66% of the total units. |
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
In General
The managing general partner will manage your partnership and its assets. In conducting your partnership’s affairs the managing general partner is accountable to you as a fiduciary, which under Delaware law generally means that the managing general partner must exercise due care and deal fairly with you and the other investors. Neither the partnership agreement nor any other agreement between the managing general partner and each partnership may contractually limit any fiduciary duty owed to you and the other investors by the managing general partner under applicable law except as set forth in Sections 4.01, 4.02, 4.03, 4.04, 4.05, and 4.06 of the partnership agreement. See “Conflicts of Interest – In General” regarding the managing general partner’s dependence on its indirect parent companies, Atlas America and Atlas Energy Resources, LLC and their affiliates, for management and administrative functions and financing for capital expenditures and “Management – Organizational Diagrams and Security Ownership of Beneficial Owners.” In this regard, the partnership agreement does permit the managing general partner and its affiliates to:
| • | have business interests or activities that may conflict with the partnerships if they determine that the business opportunity either: |
| • | cannot be pursued by the partnership because of insufficient funds; or |
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| • | it is not appropriate for the partnership under the existing circumstances; |
| • | devote only so much of their time as is necessary to manage the affairs of each partnership, as determined by the managing general partner in its sole discretion; |
| • | conduct business with the partnerships in a capacity other than as managing general partner or sponsor as described in §§4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement; |
| • | manage multiple programs simultaneously; and |
| • | be indemnified and held harmless as described below in “– Limitations on Managing General Partner Liability as Fiduciary.” |
The fiduciary duty owed by the managing general partner to the partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders, which is commonly referred to as the “business judgment rule.” This rule provides that directors are not liable for mistakes made in the good faith exercise of honest business judgment or for losses incurred in the good faith performance of their duties when performed with such care as an ordinarily prudent person would use.
If the managing general partner breaches its fiduciary responsibilities, then you are entitled to an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised Uniform Limited Partnership Act provides that a limited partner may institute legal action (a “derivative” action) on a partnership’s behalf to recover damages from a third-party when the managing general partner refuses to institute the action or where an effort to cause the managing general partner to do so is not likely to succeed. In addition, the statutory or case law may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners (a “class action”) to recover damages from the managing general partner for violations of its fiduciary duties to the limited partners. This is a rapidly expanding and changing area of the law, and if you have questions concerning the managing general partner’s duties you are urged to consult your own counsel.
Limitations on Managing General Partner Liability as Fiduciary
Under the terms of the partnership agreement the managing general partner, the operator, and their affiliates have limited their liability to each partnership and to you and the other investors for any loss suffered by your partnership or you and the other investors in the partnership which arises out of any action or inaction on their part if:
| • | they determined in good faith that the course of conduct was in the best interest of the partnership; |
| • | they were acting on behalf of, or performing services for, the partnership; and |
| • | their course of conduct did not constitute negligence or misconduct. |
In addition, the partnership agreement provides for indemnification of the managing general partner, the operator, and their affiliates by each partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with that partnership 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 the partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, you should be aware that in the SEC’s opinion this indemnification provision would be contrary to public policy and therefore unenforceable.
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Payments to the managing general partner or its affiliates arising from the indemnification or agreement to hold harmless provisions of the partnership agreement are recoverable only out of the partnership’s tangible net assets, which include its revenues and any insurance proceeds from the types of insurance for which the managing general partner, the operator and their affiliates may be indemnified under the partnership agreement. Still, the use of partnership funds or assets to indemnify the managing general partner, the operator, or an affiliate would reduce amounts available for partnership operations or for distribution to you and the other investors.
A partnership may not pay the cost of the portion of any insurance that insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. However, a partnership’s funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if the partnership has adequate funds available and certain conditions in the partnership agreement are met.
The effect of the foregoing provisions and the business judgment rule may be to limit your recourse against the managing general partner.
FEDERAL INCOME TAX CONSEQUENCES
Introduction
Because no advance ruling on any federal tax issue of an investment in a partnership will be requested from the IRS, the IRS could disagree with the tax position taken by the partnerships. However, the managing general partner has obtained a tax opinion letter from Kunzman & Bollinger, Inc., special counsel for this offering, with respect to the material and any significant federal income tax issues involving an investment in a partnership by a “typical investor” as that term is defined in “– Managing General Partner’s Representations,” below. You are urged to read the entire tax opinion letter, which has been filed as Exhibit 8 to the registration statement of which this prospectus is a part. (See “Additional Information,” for information on how to obtain a copy of special counsel’s tax opinion letter.)
Although special counsel’s tax opinions express what it believes a court would probably conclude if presented with the applicable federal tax issues, special counsel’s tax opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. The IRS could challenge special counsel’s tax opinions, and the challenge could be sustained in the courts if litigated and cause adverse tax consequences to you and your partnership’s other investors. Special counsel’s tax opinions are based in part on representations and statements made by the managing general partner in the tax opinion letter and in this prospectus, including forward looking statements relating to the partnership and its proposed activities. (See “Forward Looking Statements and Associated Risks.”)
Disclosures in Tax Opinion Letter
The following disclosures are made in special counsel’s tax opinion letter.
| • | The tax opinion letter was written to support the promotion or marketing of units in the partnerships to potential investors, and special counsel to the partnerships has helped the managing general partner organize and document the offering of units in the partnerships. |
| • | The tax opinion letter is not confidential. There are no limitations on the disclosure by any potential investor in a partnership to any other person of the tax treatment or tax structure of the partnerships. |
| • | Investors in a partnership have no contractual protection against the possibility that a portion or all of their intended tax benefits from an investment in the partnership ultimately are not sustained if challenged by the IRS. (See “Risk Factors – Tax Risks – Your Tax Benefits from an Investment in a Partnership Are Not Contractually Protected.”) |
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| • | Each potential investor in a partnership is urged to seek advice based on his particular circumstances from an independent tax advisor with respect to the federal tax consequences to him of an investment in a partnership. |
Special Counsel’s Assumptions
Set forth below is a synopsis of the principal assumptions made by special counsel in giving its federal income tax opinions.
| • | You will not borrow money to buy units in a partnership from any other investor in the partnership. |
| • | You will be personally liable to repay any money you borrow to buy units in a partnership. |
| • | You will not protect yourself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from losing the money you invest in a partnership. |
Managing General Partner’s Representations
In giving its opinions, special counsel relied in part on representations from the managing general partner set forth in the tax opinion letter, including the principal representations summarized below.
| • | A “typical investor” in each partnership will be a natural person who purchases units in this offering and is a U.S. citizen. |
| • | The investor general partner units in each partnership will be converted by the managing general partner to limited partner units after all of the wells in that partnership have been drilled and completed. (See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.” |
| • | Each partnership will elect to currently deduct all of the intangible drilling costs of all of its wells. |
| • | The managing general partner anticipates that all of each partnership’s subscription proceeds will be expended in 2007, and you will include your share of your partnership’s deduction for intangible drilling costs on your individual federal income tax return for 2007, subject to your right to elect to capitalize and amortize over a 60-month period a portion or all of your share of your partnership’s deduction for intangible drilling costs. |
| • | Each partnership may have its final closing as late in the year as December 31, 2007. Thus, depending primarily on when its subscription proceeds are received, each partnership may prepay in 2007 most, if not all, of its intangible drilling costs for wells the drilling of which will not begin until 2008. |
| • | Each partnership will have a calendar year taxable year. |
| • | The managing general partner anticipates that most, if not all, of each partnership’s natural gas and oil production from its productive wells will be marginal production that will qualify for the potentially higher rates of percentage depletion and potentially available marginal well production credits depending primarily on the applicable reference prices for natural gas and oil, which may vary from year to year. |
| • | The principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as discussed in this prospectus. |
| • | Each partnership’s total abandonment losses under §165 of the Code, which could include, for example, abandonment losses incurred by a partnership for wells drilled which are nonproductive (i.e. a “dry hole”), and abandonment losses incurred by a partnership for productive wells which have been operated until their commercial natural gas and oil reserves have been depleted, will be less than $2 million, in the aggregate, in any taxable year of each partnership and less than $4 million, in the aggregate, during each partnership’s first six taxable years. |
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Additional details, assumptions of special counsel, representations of the managing general partner, and other matters affecting special counsel’s opinions are contained in special counsel’s tax opinion letter. You are urged to read the entire tax opinion letter, which is attached as Exhibit 8 to the Registration Statement of which this prospectus is a part, to assist your understanding of the federal tax benefits and risks of an investment in a partnership.
Special Counsel’s Opinions
Taxpayers bear the burden of proof to support claimed deductions and tax credits, and special counsel’s tax opinions are not binding on the IRS or the courts. Special counsel’s tax opinions with respect to an investment in a partnership by a typical investor, who is sometimes referred to in special counsel’s opinions as a “Participant,” “Investor General Partner” or “Limited Partner,” are set forth below.
| (1) | Partnership Classification. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. |
| (2) | Limitations on Passive Activity Losses and Credits. The passive activity limitations on losses and credits under §469 of the Code will apply to: |
| • | the initial Limited Partners in a Partnership; and |
| • | will not apply to the Investor General Partners in a Partnership until after their Investor General Partner Units are converted to Limited Partner Units. |
| (3) | Not a Publicly Traded Partnership. Neither Partnership will be treated as a publicly traded partnership under the Code. |
| (4) | Business Expenses. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued by a Partnership, which are reasonable, ordinary and necessary and do not include amounts for items such as Lease acquisition costs, Tangible Costs, Organization and Offering Costs and other items that are required to be capitalized under the Code, are currently deductible by each Partnership. |
| • | Potential Limitations on Deductions. A Participant’s ability in any taxable year to use his share of these deductions of the Partnership in which he invests on his individual federal income tax returns may be reduced, eliminated or deferred by the following limitations: |
| • | the Participant’s personal tax situation, such as the amount of his regular taxable income, alternative minimum taxable income, losses, itemized deductions, personal exemptions, etc., which are not related to his investment in a Partnership; |
| • | the amount of the Participant’s adjusted basis in his Units at the end of the Partnership’s taxable year; |
| • | the amount of the Participant’s “at risk” amount in the Partnership in which he invests at the end of the Partnership’s taxable year; and |
| • | the passive activity limitations on losses, and credits, if any, of the Partnership in which they invest in the case of Limited Partners (including Investor General Partners after their Units are converted to Limited Partner Units) who are natural persons or are entities that also are subject to the passive activity limitations on losses and credits under §469 of the Code. |
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| (5) | Intangible Drilling Costs. Although each Partnership will elect to deduct currently all of its Intangible Drilling Costs, each Participant in a Partnership may still elect to capitalize and deduct all or part of his share of his Partnership’s Intangible Drilling Costs (which do not include drilling and completion costs of a re-entry well that are not related to deepening the well, if any) ratably over a 60-month period. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership’s wells will be deductible by Participants in that Partnership who elect to currently deduct their share of their Partnership’s Intangible Drilling Costs in the taxable year in which the payments are made and the drilling services are rendered. |
A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.
| (6) | Prepaid Intangible Drilling Costs. Subject to each Participant’s election to capitalize and amortize a portion or all of his share of his Partnership’s Intangible Drilling Costs as set forth in opinion (5) above, any prepayments of Intangible Drilling Costs by a Partnership in 2007 for wells the drilling of which will begin after December 31, 2007, but on or before March 30, 2008, will be deductible by the Participants in 2007. |
A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4) above.
| (7) | Depletion Allowance. The greater of the cost depletion allowance or the percentage depletion allowance will be available to qualified Participants as a current deduction against their share of their Partnership’s gross income from the sale of natural gas and oil production in each taxable year, subject to the following restrictions: |
| • | a Participant’s cost depletion allowance cannot exceed his adjusted tax basis in the natural gas or oil property to which it relates; and |
| • | a Participant’s percentage depletion allowance: |
| • | may not exceed 100% of his taxable income from each natural gas and oil property before the deduction for depletion, however, this limitation is suspended for 2007; and |
| • | is limited to 65% of his taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of a Participant that is a trust, any distributions to its beneficiaries. |
| (8) | MACRS. Each Partnership’s reasonable Tangible Costs for equipment placed in its productive wells that cannot be deducted immediately will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System (“MACRS”) over a seven year “cost recovery period” on a well-by-well basis, beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service. |
A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4), above.
| (9) | Tax Basis of Units. Each Participant’s initial adjusted tax basis in his Units will be the amount of money that he paid for his Units. |
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| (10) | At Risk Limitation on Losses. Each Participant’s initial “at risk” amount in the Partnership in which he invests will be the amount of money that he paid for his Units. |
| (11) | Allocations. The allocations of income, gain, loss, deduction, and credit, or items thereof, and distributions set forth in the Partnership Agreement for each Partnership, including the allocations of basis and amount realized with respect to a Partnership’s natural gas and oil properties, will govern each Participant’s allocable share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account in the Partnership in which he invests. |
| (12) | Subscription. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest. |
| (13) | Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines. The Partnerships will possess the requisite profit motive under §183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg. §1.701-2 and potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a Participant as described in our opinions. |
| (14) | Reportable Transactions. Neither Partnership is, nor should be in the future, a reportable transactions under §6707A(c) of the Code. |
| (15) | Overall Conclusion. Special counsel’s overall conclusion is that the federal tax treatment of a typical Participant’s investment in a Partnership as set forth in its opinions above is the proper federal tax treatment and will be upheld on the merits if challenged by the IRS and litigated. Our evaluation of the federal income tax laws and the expected activities of the Partnerships as represented to us by the Managing General Partner in this tax opinion letter and as described in the Prospectus causes us to believe that the deduction by a typical Participant of all, or substantially all, of his allocable share of his Partnership’s Intangible Drilling Costs in 2007 (even if the drilling of most or all of his Partnership’s wells begins after December 31, 2007, but on or before March 30, 2008), as set forth in opinions (5) and (6) above, is the principal tax benefit offered by each Partnership to its potential Participants and also is the proper federal tax treatment, subject to each Participant’s election to capitalize and amortize a portion or all of his share of his Partnership’s deduction for Intangible Drilling. |
A Participant’s ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in opinion (4), above.
The discussion in the Prospectus under the caption “FEDERAL INCOME TAX CONSEQUENCES,” insofar as it contains statements of federal income tax law, is correct in all material respects.
Discussion of Federal Income Tax Consequences
Introduction
Special counsel’s tax opinions are limited to those set forth above. The following is a discussion of all material federal income tax issues or consequences, and any significant federal tax issues, related to the purchase, ownership and disposition of a partnership’s units that will apply to typical investors in each partnership. Except as otherwise noted below, however, different tax consequences from those discussed below may apply to foreign persons, corporations, partnerships, trusts and other prospective investors that are not treated as typical investors for federal income tax purposes. Also, the proper treatment of a partnership’s tax attributes by a typical investor on his individual federal income tax returns may vary from that of another typical investor. This is because the practical utility of the tax aspects of any investment depends largely on each investor’s particular income tax position in the year in which items of income, gain, loss, deduction, or credit, if any, are properly taken into account in computing his federal income tax liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by a partnership or you and the other investors in a partnership, or the taxable year in which the deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, you are urged to seek advice based on your particular circumstances from an independent tax advisor in evaluating the potential tax consequences to you of an investment in a partnership.
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Partnership Classification
For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather than the partnership, receive and report any deductions and tax credits, if any, as well as the income, from a partnership’s operations. Each partnership has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act, which describes each partnership as a “partnership.” Thus, each partnership automatically will be classified as a partnership for federal tax purposes since the managing general partner has represented that neither partnership will elect to be taxed as a corporation. Treas. Reg. §301.7701-2.
The managing general partner anticipates that all of the subscription proceeds of each partnership will be expended in 2007, and the related income, if any, and deductions, including the deduction for intangible drilling costs, will be reflected on their respective investors’ federal income tax returns for 2007, subject to each investor’s right to elect to capitalize and amortize over a 60-month period a portion or all of the investor’s share of his partnership’s deduction for intangible drilling costs. See “Capitalization and Source of Funds and Use of Proceeds” and “Participation in Costs and Revenues” and “– Intangible Drilling Costs,” “– Drilling Contracts,” “– Depletion Allowance,” “– Depreciation and Cost Recovery Deductions” and “– Alternative Minimum Tax,” below.).
Limitations on Passive Activity Losses and Credits
Under the passive activity rules of §469 of the Code, all income of a taxpayer who is subject to the rules is categorized as:
| • | income from passive activities, such as limited partners’ interests in a business; |
| • | active income, such as salary, bonuses, etc.; or |
| • | portfolio income, such as gain, interest, dividends and royalties unless earned in the ordinary course of a trade or business, and gain not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment. |
Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Similar rules apply with respect to tax credits. (See “– Marginal Well Production Credits,” below.) Suspended passive losses and passive credits that an investor cannot use in his current tax year may be carried forward indefinitely, but not back, and used to offset future years’ passive activity income, or offset passive activity regular federal income tax liability (in the case of passive activity credits).
The passive activity rules apply to:
| • | individuals, estates, and trusts; |
| • | closely held C corporations which under §§469(j)(1), 465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with five or fewer individuals who own directly or indirectly more than 50% in value of the outstanding stock at any time during the last half of the taxable year (for this purpose, U.S. trusts forming part of a stock bonus, pension or profit-sharing plan of an employer for the exclusive benefit of its employees or their beneficiaries that constitutes a “qualified trust” under §401(a) of the Code, trusts forming part of a plan providing for the payment of supplemental employee unemployment compensation benefits that meet the requirements of §501(c)(17) of the Code, domestic or foreign “private foundations” described in §501(c)(3) of the Code, and a portion of a trust permanently set aside or to be used exclusively for the charitable purposes described in §642(c) of the Code or a corresponding provision of a prior income tax law, are considered to be individuals); and |
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| • | personal service corporations, which under §§469(j)(2), 269A(b) and 318(a)(2)(C) of the Code are corporations the principal activity of which is the performance of personal services and those services are substantially performed by employee-owners. For this purpose, the term “employee-owners” includes any employee who owns, on any day during the taxable year, any of the outstanding stock of the personal service corporation, and an employee is considered to own: |
| • | the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a partnership or estate in which the employee is a partner or beneficiary; |
| • | the employee’s proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a trust (other than an employee’s trust that is a qualified pension, profit-sharing, or stock bonus plan and is exempt from the tax) if the employee is a beneficiary; |
| • | all of the stock of the personal service corporation owned, directly or indirectly, by or for any portion of a trust of that the employee is considered the owner under the Code; and |
| • | if any stock in a corporation is owned, directly or indirectly, for or by the employee, the employee’s portionate share of the stock of the personal service corporation owned, directly or indirectly, by or for that corporation. |
Provided, however, that a corporation will not be treated as a personal service corporation for purposes of §469 of the Code unless more than 10% of the stock (by value) in the corporation is held by employee-owners (as described above). I.R.C. §469(j)(2)(B).
However, if a closely held C corporation, other than a personal service corporation in which employee-owners own more than 10% (by value) of the stock, has net active income (i.e., taxable income determined without regard to any income or loss from a passive activity and without regard to any item of portfolio income, expense (including interest expense), or gain or loss) for a taxable year, its passive loss for that taxable year can be applied against its net active income for that taxable year. Similar rules apply to its passive credits, if any. I.R.C. §469(e)(2).
Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the partnership agreement, limited partners will not have material participation in the partnership in which they invest. Thus, if you are subject to the passive activity rules as described above and you invest in a partnership as a limited partner, your investment in the partnership will be subject to the passive activity limitations on losses and credits. (See “Risk Factors – Tax Risks – Limited Partners Need Passive Income to Use Their Deduction for Intangible Drilling Costs.”)
Investor general partners also will not materially participate in the partnership in which they invest. However, because each partnership will own only “working interests,” as defined by the Code, in its wells, and investor general partners will not have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are converted to limited partners, their deductions and any credits from their partnership will not be treated as passive deductions or credits under the Code before the conversion, unless they invest in a partnership through an entity which limits their liability. For example, if an individual invests in a partnership indirectly as an investor general partner by using an entity that limits his personal liability under state law to purchase his units, such as a limited partnership in which he is not a general partner, a limited liability company or an S corporation, he will be subject to the passive activity limitations on deductions and credits the same as if he had invested in the partnership as a limited partner. (See “– Conversion from Investor General Partner to Limited Partner” and “– Marginal Well Production Credits,” below.)
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As compared with limitations on liability under state law as discussed above, contractual limitations on the liability of investor general partners under the partnership agreement, such as insurance, limited indemnification by the managing general partner, etc. will not cause investor general partners to be subject to the passive activity limitations on losses and credits. Investor general partners, however, may be subject to an additional limitation on their deduction of investment interest expense as a result of their non-passive deduction of intangible drilling costs. (See “– Limitations on Deduction of Investment Interest,” below.)
A Limited Partner’s “at risk” amount is reduced by losses allowed under §465 of the Code even if the losses are suspended by the passive activity limitations. (See “– ‘At Risk’ Limitation on Losses,” below.) Similarly, a Limited Partner’s basis is reduced by deductions even if the deductions are suspended under the passive activity limitations. (See “– Tax Basis of Units,” below.)
Suspended passive losses and passive credits that cannot be used by a taxpayer in his current tax year may be carried forward indefinitely, but not back, and can be used to offset passive income in future years or, in the case of passive credits, can be used to offset regular federal income tax liability attributable to passive income in future years. I.R.C. §469(b). A suspended passive loss, but not a suspended passive credit, is allowed in full when a taxpayer’s entire interest in a passive activity is sold to an unrelated third-party in a fully taxable transaction, and in part on the taxable disposition of substantially all of a taxpayer’s interest in a passive activity if the suspended passive loss as well as current gross income and deductions of the passive activity can be allocated to the part disposed of with reasonable certainty. I.R.C. §469(g)(1). In an installment sale of a taxpayer’s entire interest in a passive activity, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. I.R.C. §469(g)(3). (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”)
Any suspended passive losses remaining at a taxpayer’s death are allowed as deductions on the decedent’s final return, subject to a reduction to the extent the amount of the suspended passive losses is greater than the excess of the basis of the property in the hands of the transferee over the property’s adjusted basis immediately before the decedent’s death. I.R.C. §469(g)(2). If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended passive losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value of the property on the date the gift was made. I.R.C. §469(j)(6).
Publicly Traded Partnership Rules
Net losses and most net credits of a partner from a publicly traded partnership are suspended and carried forward to be netted against income or regular federal income tax liability, respectively, from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. I.R.C. §§469(k)(2) and 7704. A publicly traded partnership is a partnership in which interests in the partnership are traded on an established securities market or are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in special counsel’s opinion neither of the partnerships will be treated as a publicly traded partnership under the Code. This opinion is based primarily on the substantial restrictions in the partnership agreement on the ability of you and the other investors to transfer your units in your partnership. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”) Also, the managing general partner has represented that the partnerships’ respective units will be not traded on an established securities market.
Conversion from Investor General Partner to Limited Partner
If you invest in a partnership as an investor general partner, then your share of the partnership’s deduction for intangible drilling costs in 2007 will not be subject to the passive activity limitations on losses and credits. This is because the investor general partner units in each partnership will not be converted to limited partner units under §6.01(b)(1) of the partnership agreement until after all of the wells in that partnership have been drilled and completed. (See “Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners,” and “– Drilling Contracts,” below.) After the investor general partner units have been converted to limited partner units, each former investor general partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act after the date of the conversion.
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Concurrently, the former investor general partner will become subject to the passive activity limitations on losses and credits as a limited partner. However, the former investor general partner previously will have received a non-passive loss as an investor general partner in 2007 as a result of his share of his partnership’s deduction for intangible drilling costs. Therefore, the Code requires that his net income from the partnership’s wells after his conversion to a limited partner must continue to be characterized as non-passive income that cannot be offset with passive losses. For a discussion of the effect of this rule on an investor general partner’s tax credits, if any, from his partnership, see “– Marginal Well Production Credits,” below. The conversion of the investor general partner units into limited partner units should not have any other adverse tax consequences on an investor general partner unless his share, if any, of any partnership liabilities is reduced as a result of the conversion. (See “– Tax Basis of Units,” below.)
Taxable Year and Method of Accounting
Each partnership will adopt a calendar year taxable year and will use the accrual method of accounting for federal income tax purposes.
Taxable Year. Each partnership will have a calendar year taxable year. I.R.C. §§706(a) and (b). The taxable year of the partnership in which you invest is important to you because your share of the partnership’s deductions, tax credits, if any, income and other items of tax significance must be taken into account on your personal federal income tax return for your taxable year within or with which the partnership’s taxable year ends.
Method of Accounting. Each partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. §448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred that fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, you and the other investors in the partnership in which you invest may have income tax liability resulting from the partnership’s accrual of income in one tax year even though it does not receive the income in cash until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under §461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used.
A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for intangible drilling costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the taxable year in which the payments were made. I.R.C. §461(i). (See “– Drilling Contracts,” below, for a discussion of the federal income tax treatment of any prepaid intangible drilling costs by the partnerships.)
Business Expenses
Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. In this regard, the managing general partner has represented that the amounts payable by each partnership to it and its affiliates under the partnership agreement and the drilling and operating agreement are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between persons having no affiliation and dealing with each other “at arms” length in the proposed areas of the partnerships’ operations. (See Treas. Reg. §1.162-7(b)(3) and “Compensation” and “– Drilling Contracts,” below.) The fees paid to the managing general partner and its affiliates by the partnerships will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are:
| • | in excess of reasonable compensation; |
| • | properly characterized as organization or syndication fees or other capital costs, such as lease acquisition costs or equipment costs (i.e., “Tangible Costs”); or |
| • | not “ordinary and necessary” business expenses. |
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In the event of an IRS audit of a partnership, payments to the managing general partner and its affiliates by the partnership would be scrutinized by the IRS to a greater extent than payments to an unrelated party.
Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Although the partnerships will engage in the production of natural gas and oil from wells drilled in the United States, the partnerships will not qualify for the “U.S. production activities deduction.” This is because the deduction cannot exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the partnerships will not pay any Form W-2 wages since they will not have any employees. Instead, the partnerships will rely on the managing general partner and its affiliates to manage them and their respective businesses. (See “Management.”)
Intangible Drilling Costs
You may elect to deduct your share of your partnership’s intangible drilling costs, which include items that do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well and preparing it for the production of natural gas or oil, in the taxable year in which your partnership’s wells are drilled and completed. I.R.C. §263(c), Treas. Reg. §1.612-4(a). For a discussion of the deduction in 2007 of intangible drilling costs that are prepaid by your partnership in 2007 for wells the drilling of which will not begin until 2008, if any, see “– Drilling Contracts,” below.
Your share of your partnership’s gain (if a partnership well is sold at a gain), or your gain (if your units are sold at a gain), will be treated as ordinary income, rather than capital gain, to the extent of the previous deductions for intangible drilling costs you have claimed, but not for the deductions for operating expenses related to a re-entry well, if any. (See “– Sale of the Properties” and “– Disposition of Units,” below.) Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct all or part of these costs ratably over a 60 month period. (See “– Alternative Minimum Tax,” below.)
Under the partnership agreement, 90% of the subscription proceeds received by each partnership from its respective investors will be used to pay 100% of the partnership’s intangible drilling costs of drilling and completing its wells. (See “Application of Proceeds” and “Participation in Costs and Revenues.”) The IRS could challenge the characterization of a portion of these costs as currently deductible intangible drilling costs and recharacterize the costs as some other item that may not be currently deductible, such as lease acquisition expenses, equipment costs or syndication fees. However, this would have no effect on the allocation and payment of the intangible drilling costs by you and the other investors under the partnership agreement.
Also, if a partnership re-enters an existing well as described in “Proposed Activities – Primary Areas of Operations – Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania,” the costs of deepening the well and completing it to deeper reservoirs, if any, other than equipment costs and lease acquisition costs, will be treated under the Code as intangible drilling costs. The remaining intangible drilling costs of drilling and completing a re-entry well that are not related to deepening the well, if any, however, will be treated under the Code as operating expenses that should be expensed in the taxable year they are incurred for federal income tax purposes. Any intangible drilling costs of a re-entry well that are treated as operating expenses for federal income tax purposes, however, will not be characterized as operating costs, instead of intangible drilling costs, for purposes of allocating the payment of the costs between the managing general partner, on the one hand, and you and the other investors , on the other hand. In addition, under the Code costs related to a re-entry well that are characterized as operating costs under the Code cannot be amortized as intangible drilling costs over a 60-month period as described in “– Alternative Minimum Tax,” below, even though they may be characterized as intangible drilling costs for purposes of the partnership agreement as discussed above. (See “Participation in Costs and Revenues.”)
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In the case of corporations, other than S corporations, which are “integrated oil companies,” the amount allowable as a deduction for intangible drilling costs in any taxable year is reduced by 30%. I.R.C. §291(b)(1). Integrated oil companies are:
| • | those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from those activities exceed $5 million; or |
| • | those taxpayers and related persons who have average daily refinery runs in excess of 75,000 barrels for the taxable year. I.R.C. §291(b)(4). |
Amounts of an integrated oil company’s intangible drilling costs that are disallowed as a current deduction under §291 of the Code are allowable, however, as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. Neither partnership will be an integrated oil company.
Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
You are urged to seek advice based on your particular circumstances from an independent tax advisor concerning the tax benefits to you of your share of the deduction for intangible drilling costs of the partnership in which you invest.
Drilling Contracts
Each partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership’s wells for an amount equal to the sum of the following items: (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee of $15,000 per well, which will be charged to you and the other investors as part of each well’s intangible drilling costs and the portion of equipment costs paid by you and the other investors; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. Notwithstanding, if the managing general partner drills a well for a partnership that it determines is not an average well in the area because of the well’s depth, complexity associated with either drilling or completing the well or as otherwise determined by the managing general partner, the administration and oversight fee of $15,000 per well described in §4.02(d)(1)(iv) of the partnership agreement may be increased to a competitive rate as determined by the managing general partner.
The managing general partner anticipates that, on average over all of the wells that are drilled and completed by each partnership, assuming a 100% working interest in each well, its mark-up of 15% will be approximately $42,254 per well with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors in your partnership as described in “Compensation – Drilling Contracts.” However, the actual cost of drilling and completing the wells may be more or less than the amounts estimated by the managing general partner, due primarily to the uncertain nature of drilling operations. Therefore, the managing general partner’s 15% mark-up discussed above also could be more or less than the dollar amount estimated by the managing general partner as set forth above. The managing general partner believes that the compensation payable to it and its affiliates under the drilling and operating agreement is competitive in the proposed areas of operation. Nevertheless, the amount of fees and profit realized by the managing general partner under the drilling and operating agreement could be challenged by the IRS as being unreasonable and disallowed as a deductible intangible drilling cost.
Depending primarily on when their respective subscription proceeds are received, the managing general partner anticipates that each partnership may prepay in 2007 most, if not all, of its intangible drilling costs for wells the drilling of which will begin in 2008. In Keller v. Commissioner, 79 T.C. 7 (1982), aff’d 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is:
| • | the expenditure must be a payment rather than a refundable deposit; and |
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| • | the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. |
The drilling partnership in Keller entered into footage and daywork drilling contracts that permitted it to terminate the contracts at any time, without a default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for the prepayments under the footage and daywork drilling contracts.
The drilling partnership in Keller also entered into turnkey drilling contracts that permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted “payments” and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated “the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well,” thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Since the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment.
In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program’s corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor’s financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all of the wells began in 1975 and all of the wells were completed in 1975. The amount paid by the general contractor to the independent driller for its work on the nine wells was approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely “contracts of convenience” designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income.
Each partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid intangible drilling costs. In this regard, the drilling and operating agreement will require each partnership to prepay in 2007 all of the partnership’s share of the estimated intangible drilling costs, and all of the investors’ share of your partnership’s share of the estimated equipment costs, for drilling and completing specified wells for that partnership, the drilling of which may begin in 2008. These prepayments of intangible drilling costs should not result in a loss of a current deduction for the intangible drilling costs in 2007 if:
| • | the guidelines set forth in Keller are complied with; |
| • | there is a legitimate business purpose for the required prepayment; |
| • | the drilling of the prepaid wells begins on or before March 30, 2008; |
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| • | the contract is not merely a sham to control the timing of the deduction; and |
| • | there is an enforceable contract of economic substance. |
In this regard, the drilling and operating agreement will require each partnership to prepay the managing general partner’s estimate of the intangible drilling costs and the investor’s share of the equipment costs to drill and complete the wells specified in the drilling and operating agreement in order to enable the operator to:
| • | begin site preparation for the wells; |
| • | obtain suitable subcontractors at the then current prices; and |
| • | insure the availability of equipment and materials. |
Under the drilling and operating agreement excess prepaid intangible drilling costs, if any, will not be refundable to a partnership, but instead will be applied only to intangible drilling cost overruns, if any, on the other specified wells being drilled or completed by the partnership or to intangible drilling costs to be incurred by the partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits.
The likelihood that prepayments of intangible drilling costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to 100% of the working interest in the well. In this regard, the managing general partner anticipates that less than 100% of the working interest will be acquired by each partnership in one or more of its wells, and prepayments of intangible drilling costs will not be required of the other owners of working interests in those wells. In the view of special counsel, however, a legitimate business purpose for the required prepayments of intangible drilling costs by the partnerships may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the working interest in the wells.
In addition, a current deduction for prepaid intangible drilling costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. See the discussion of §461(i) of the Code in “– Method of Accounting,” above. Therefore, under the drilling and operating agreement, the managing general partner, serving as operator and general drilling contractor, must begin drilling the wells that are prepaid by the partnership in 2007, if any, no later than March 30, 2008, which is before the close of the 90th day after the close of the 2007 calendar taxable year of each partnership in which a partnership’s intangible drilling costs are prepaid. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner and the drilling subcontractors. These circumstances include, for example:
| • | the unavailability of drilling rigs; |
| • | decisions of third-party operators to delay drilling the wells; |
| • | poor weather conditions; |
| • | inability to obtain drilling permits or access right to the drilling site; or |
and the managing general partner will have no liability under the partnership agreement or the drilling and operating agreement to either partnership or their respective investors if these types of events (i.e., “force majeure”) delay beginning the drilling of any partnership prepaid well beyond the 90 day limit imposed by §461(i) of the Code (i.e., March 30, 2008).
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If the drilling of a prepaid partnership well does not begin within the 90 day time constraint imposed by §461(i) of the Code (i.e., March 30, 2008), deductions claimed by you and the other investors in that partnership for prepaid intangible drilling costs for the well in 2007, would not be lost, but those deductions would be deferred to 2008 when the well is actually drilled.
Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Depletion Allowance
Proceeds from the sale of each partnership’s natural gas and oil production will constitute ordinary income. A portion of that income will not be taxable under the depletion allowance, which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. §§611, 613 and 613A. Your share of your partnership’s gain (if a partnership well is sold at a gain), or your gain (if you sell your units at a gain), will be treated as ordinary income rather than capital gain to the extent of your previous deductions for depletion that reduced your adjusted basis in the property or your units. (See “– Sale of the Properties” and “– Disposition of Units,” below.)
Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates.
Percentage depletion is available to taxpayers other than “integrated oil companies,” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnerships. Your percentage depletion allowance is based on your share of your partnership’s gross production income from its natural gas and oil properties. Under §613A(c) of the Code, percentage depletion is available with respect to 6 million cubic feet of average daily production of domestic natural gas or 1,000 barrels of average daily production of domestic crude oil. However, taxpayers who have both natural gas and oil production may allocate the production limitation between the production.
The rate of percentage depletion is 15%. However, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. I.R.C. §613A(c)(6). The term “marginal production” includes natural gas and oil produced from a domestic stripper well property, which is defined in §613A(c)(6)(E) of the Code as any property that produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. In this regard, the managing general partner has represented that most, if not all, of the natural gas and oil production from each partnership’s productive wells will be marginal production under this definition in the Code. Therefore, most, if not all, of each partnership’s gross income from the sale of its natural gas and oil production will qualify for these potentially higher rates of percentage depletion. The managing general partner anticipates that the rate of percentage depletion for marginal production in 2007 will be 15%. This rate may fluctuate from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%.
Also, percentage depletion:
| • | may not exceed 100% of the taxable income from each natural gas and oil property before the deduction for depletion, however, this limitation has been suspended in 2007 with respect to marginal properties, which the managing general partner has represented will include most, if not all, of each partnership’s wells; and |
| • | is limited to 65% of the taxpayer’s taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of an investor that is a trust, any distributions to its beneficiaries. Any disallowed percentage depletion deductions under this limitation may be carried forward to the next taxable year. |
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The availability in any taxable year of the percentage depletion allowance must be computed separately by you and not by your partnership or for investors in your partnership as a whole. You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the availability of the percentage depletion allowance to you.
Depreciation and Cost Recovery Deductions
Ten percent of each partnership’s subscription proceeds from you and the other investors will be used to pay equipment costs (i.e. “Tangible Costs”), and the managing general partner will pay all of the partnership’s remaining equipment costs of drilling and completing its wells. The related depreciation deductions, i.e., cost recovery deductions under the modified accelerated cost recovery system (“MACRS”), will be allocated under the partnership agreement between the managing general partner, on the one hand, and you and the other investors in each partnership, on the other hand, in proportion to the actual amount of the partnership’s equipment costs paid by each.
A partnership’s reasonable Tangible Costs for equipment placed in its wells that cannot be deducted immediately will be recovered through depreciation deductions over a seven year cost recovery period, using the 200% declining balance method with a switch to straight-line to maximize the deduction, beginning in the taxable year in which each well is drilled, completed and made capable of production, (i.e., “placed in service”) by the partnership. I.R.C. §168(c). In this regard, the managing general partner anticipates that it may take up to 12 months before all of a partnership’s wells are drilled, completed and placed in service for the production of natural gas or oil after that partnership’s final closing. In the case of a short partnership tax year, the MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Under §168(d)(1) of the Code, all property assigned to the 7-year class is treated as placed in service, or disposed of, in the middle of the year, unless more than 40% of the total cost of all equipment in a partnership’s wells placed in service during the year is placed in service during the last three months of the year. If that happens, then under §168(d)(3) of the Code the depreciation for the full year will be multiplied by a fraction based on the quarter the equipment is placed in service: 87.5% for the first quarter, 62.5% for the second, 37.5% for the third, and 12.5% for the fourth. All of these cost recovery deductions claimed by a partnership and you and the other investors in that partnership are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property by the partnership or your units by you. (See “– Sale of the Properties” and “– Disposition of Units,” below.) Depreciation for alternative minimum tax purposes is computed using the 150% declining balance method switching to straight-line, for most personal property. This will result in adjustments in computing the alternative minimum taxable income of you and the other investors in a partnership in taxable years in which the partnership claims depreciation deductions. (See “– Alternative Minimum Tax,” below.)
Your ability in any taxable year to use your share of these partnership deductions on your personal federal income tax returns may be reduced, eliminated or deferred by the “Potential Limitations on Deductions” set forth in special counsel’s opinion (4) in “Special Counsel’s Opinions,” above.
Marginal Well Production Credits
There is a marginal well production credit of 50¢ per mcf of qualified natural gas production and $3 per barrel of qualified oil production for purposes of the regular federal income tax. A tax credit, unlike a tax deduction, reduces tax liability on a dollar-for-dollar basis. This credit is part of the general business credit under §38 of the Code, but under current law this credit cannot be used against the alternative minimum tax. (See “– Alternative Minimum Tax,” below.) Natural gas and oil production that qualifies as marginal production under the percentage depletion rules of §613A(c)(6) of the Code as discussed above in “– Depletion Allowance,” which the managing general partner has represented will include most, if not all, of the natural gas and oil production from each partnership’s productive wells, is also qualified marginal production for purposes of this credit. Also, the credit will be reduced proportionately if the reference prices for the previous calendar year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil. In this regard, the managing general partner anticipates that neither of the partnership’s natural gas and oil production in 2007, if any, will qualify for this credit, because as of the date of this prospectus the prices for natural gas and oil in 2006 were substantially above the $2.00 per mcf of natural gas and $18.00 per barrel of oil prices where the credit phases out completely.
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Based on the prices for natural gas and oil in recent years compared with the prices at which the credit phases out completely, it may appear unlikely that either partnership’s natural gas and oil production will ever qualify for this credit. (See “Proposed Activities – Sale of Natural Gas Production – Policy of Treating All Wells Equally in a Geographic Area.”) However, prices for natural gas and oil are volatile and could decrease in the future. (See “Risk Factors – Risks Related To The Partnerships’ Oil and Gas Operations – Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil.”) Thus, it is possible that the partnerships’ production of natural gas or oil in one or more taxable years after 2007 could qualify for the marginal well production credit, depending primarily on the applicable reference prices for natural gas and oil in the future. However, depending primarily on market prices for natural gas and oil, which are volatile, each partnership’s production of natural gas and oil may not qualify for marginal well production credits for many years, if ever.
To the extent that your share of your partnership’s marginal well production credits, if any, exceeds your regular federal income tax owed on your share of the partnership’s taxable income, the excess credits, if any, can be used by you to offset any other regular federal income taxes owed by you, on a dollar-for-dollar basis, subject to the passive activity limitations if you invest in a partnership as a limited partner. (See “– Limitations on Passive Activity Losses and Credits,” above.) Also, if you invest in a partnership as an investor general partner, your share of your partnership’s marginal well production credits, if any, will be an active credit that may offset your regular federal income tax liability on any type of income. However, after you are converted to a limited partner in the partnership in which you invest, your share of the partnership’s marginal well production credits, if any, will be active credits only to the extent of your regular federal income tax liability that is allocable to your share of any net income of the partnership from the sale of its natural gas and oil production, since your share of that net income must continue to be treated by you as non-passive income even after you have been converted to a limited partner. (See “– Conversion from Investor General Partner to Limited Partner,” above.) Any credits allocable to you as a converted investor general partner in excess of that amount, as well as all of the marginal well production credits allocable to those investors who originally invest in the partnership as limited partners, will be passive credits that under current law can reduce only your regular income tax liability attributable to net passive income from the partnership in which you invest or your other passive activities, if any, other than publicly traded partnership passive activities.
Lease Acquisition Costs and Abandonment
Lease acquisition costs, together with the related cost depletion deduction, and any amortization deductions for geological and geophysical expenses incurred by the managing general partner after August 8, 2005, with respect to a partnership’s prospects and any abandonment loss for lease acquisition costs, are allocated under the partnership agreement 100% to the managing general partner, which will contribute the leases to each partnership as a part of its capital contribution.
Tax Basis of Units
Your share of your partnership’s losses is allowable only to the extent of the adjusted basis of your units at the end of your partnership’s taxable year. I.R.C. §704(d). The adjusted basis of your units will be adjusted, but not below zero, for any gain or loss to you from a sale or other taxable disposition by your partnership of a natural gas or oil property, and will be increased by your:
| • | cash subscription payment; |
| • | share of partnership income; and |
| • | share, if any, of partnership debt. |
The adjusted basis of your units will be reduced by your:
| • | share of partnership losses; |
| • | share of partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account; |
| • | depletion deductions, but not below zero; |
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| • | cash distributions from the partnership; and |
| • | any reduction in your share of your partnership’s debt, if any. I.R.C. §§705, 722 and 742. |
The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Although you will not be personally liable on any partnership loans, if you invest in a partnership as an investor general partner you will be liable for other obligations of the partnership. (See “Risk Factors – Risks Related to an Investment In a Partnership – If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner.”) Should cash distributions to you from your partnership exceed the tax basis of your units immediately before the distributions, taxable gain would result to you to the extent of the excess. (See “– Distributions From a Partnership,” below.)
“At Risk” Limitation on Losses
You may use your share of your partnership’s losses to offset income from other sources, to the extent that your use of those losses is not limited by the adjusted tax basis of your units or the passive activity limitations on losses and credits, but only to the extent of the amount you have “at risk” in the partnership under §465 of the Code at the end of a taxable year. (See
“– Limitations on Passive Activity Losses and Credits” and “– Tax Basis of Units,” above.) “Loss,” for purposes of the “at risk” rules, means the excess of your share of the allocable deductions for a taxable year from the partnership in which you invest over the amount of income actually received or accrued by you during the year from that partnership. This “at risk” limitation on your share of your partnership’s losses, however, does not apply to you if you are a corporation that is neither an S corporation nor a corporation in which at any time during the last half of the taxable year five or fewer individuals owned more than 50% (in value) of the outstanding stock under §542(a)(2) of the Code. (See “– Limitations on Passive Activity Losses and Credits,” above, relating to the application of §469 of the Code to closely held C corporations for additional information on the stock ownership requirements under §542(a)(2) of the Code.
Your initial “at risk” amount in the partnership in which you invest will be equal to the amount of money you paid for your units. However, any amounts borrowed by you to buy your units will not be considered “at risk” if the amounts are borrowed from another investor in your partnership or anyone related to another investor in your partnership. In this regard, the managing general partner has represented that it and its affiliates will not make or arrange financing for you or any other potential investors to use to purchase units in the partnerships. Also, the amount you have “at risk” in your partnership will not include the amount of any loss that you are protected against through:
| • | stop loss agreements; or |
| • | other similar arrangements. |
The amount of any loss that exceeds your “at risk” amount in the partnership in which you invest at the end of any taxable year must be carried forward by you to the next taxable year, and will then be available to the extent you are “at risk” in the partnership at the end of that taxable year. Further, your “at risk” amount in subsequent taxable years of the partnership will be reduced by any portion of a partnership loss that is allowable to you as a deduction.
Since income, gains, losses and distributions of the partnership in which you invest will affect your “at risk” amount in the partnership, the extent to which you are “at risk” in the partnership must be determined annually. Previously allowed losses must be included in your gross income if your “at risk” amount is reduced below zero. The amount included in your income, however, may be deducted in the next taxable year to the extent of any increase in the amount that you have “at risk” in your partnership.
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Distributions From a Partnership
A cash distribution from your partnership to you in excess of the adjusted basis of your units immediately before the distribution is treated as gain to you from the sale or exchange of your units to the extent of the excess. I.R.C. §731(a)(1). Different rules apply, however, to payments by a partnership to a deceased investor’s successor in interest and to payments for an investor’s share of his partnership’s unrealized receivables and inventory items as those terms are defined in §751 of the Code. Under §731(a)(2) of the Code, no loss can be recognized by you on these types of distributions, unless the distribution is made to liquidate your units in your partnership and then only to the extent of the excess, if any, of your adjusted basis in your units over the sum of the amount of money distributed to you plus your share of the basis (as determined under §732 of the Code) of any unrealized receivables and inventory items of your partnership. (See
“– Disposition of Units,” below, for a discussion of a partnership’s unrealized receivables and inventory items under §751 of the Code.)
No gain or loss will be recognized by the partnership in which you invest on cash distributions to you and the other investors. I.R.C. §731(b). If property is distributed by the partnership to the managing general partner and you and the other investors in that partnership, basis adjustments to the partnership’s properties may be made by the partnership, and adjustments to the basis in their respective interests in the partnership may be made by the managing general partner and you and the other investors. I.R.C. §§732, 733, 734, and 754. (See §5.04(d) of the Partnership Agreement and “– Tax Elections,” below.) Other distributions of cash, disproportionate distributions of property, if any, and liquidating distributions of the partnership may result in taxable gain or loss to you and the other investors.
Sale of the Properties
The maximum tax rate on a noncorporate taxpayer’s adjusted net capital gain on the sale of most capital assets held more than a year is 15%, or 5% to the extent the gain would have been taxed at a 10% or 15% rate if it had been ordinary income, respectively, for most capital assets. In addition, the 5% tax rate on adjusted net capital gain will be reduced to 0%. The former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain have been eliminated. These capital gain rates also apply for purposes of the alternative minimum tax. (See “– Alternative Minimum Tax,” below.) However, the former tax rates on adjusted net capital gain of 20% and 10%, respectively, are scheduled to be reinstated on January 1, 2011.
Under §1(h)(3) of the Code, “adjusted net capital gain” means net capital gain determined without taking qualified dividend income into account:
| • | reduced (but not below zero) by: |
| • | any amount of qualified dividend income taken into account as investment income under §163(d)(4)(B)(iii) of the Code; |
| • | net capital gain that is taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of qualified small business stock qualified under §1202 of the Code); and |
| • | net capital gain that is taxed at a maximum rate of 25% (gain attributable to real estate depreciation); and |
| • | increased by the amount of qualified dividend income. |
“Net capital gain” means the excess of net long-term gain (the excess of long-term gains over long-term losses) over net short-term loss (the excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. §1211(b)
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Gains from the sale by a partnership of a natural gas and oil property held by it for more than 12 months will be treated as long-term capital gain, while a net loss will be an ordinary deduction, except to the extent of depreciation recapture on equipment and recapture of intangible drilling costs and depletion deductions as discussed below. In addition, gain on the sale of the partnership’s natural gas and oil properties may be recaptured as ordinary income to the extent of non-recaptured §1231 losses (as defined below) for the five most recent preceding taxable years on previous sales, if any, of the partnership’s natural gas and oil properties or other assets. I.R.C. §1231(c). If, for any taxable year, the §1231 gains exceed the §1231 losses, the gains and losses will be treated as long-term capital gains or long-term capital losses, as the case may be. If the §1231 gains do not exceed the §1231 losses, the gains and losses will not be treated as gains and losses from sales or exchanges of capital assets. For this purpose, the term “§1231 gain” means any recognized gain:
| • | on the sale or exchange of a property used in a trade or business; and |
| • | from the involuntary conversion into other property or money of: |
| • | property used in a trade or business; or |
| • | any capital assets that are held for more than one year and are held in connection with a trade or business or a transaction entered into for profit. |
The term “§1231 loss” means any recognized loss from a sale or exchange or conversion described above.
The term “property used in a trade or business” means depreciable property and real property that are used in a trade or business and are held for more than one year, which are not inventory and are not held primarily for sale to customers in the ordinary course of a trade or business.
Net §1231 gain will be treated as ordinary income to the extent the gain does not exceed the non-recaptured net §1231 losses. The term “non-recaptured net §1231 losses” means the excess of:
| • | the aggregate amount of the net §1231 losses for the five most recent taxable years; over |
| • | the portion of those losses taken into account to determine whether the net §1231 gain for any taxable year should be treated as ordinary income to the extent the gain does not exceed the non-recaptured net §1231 losses, as discussed above, for those preceding taxable years. |
Other gains and losses on sales of natural gas and oil properties held by the partnership for less than 12 months, if any, will result in ordinary gains or losses.
In addition, as discussed above deductions for intangible drilling costs and depletion allowances that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by the partnership. The amount of gain recaptured as ordinary income is the lesser of:
| • | the aggregate amount of expenditures that have been deducted as intangible drilling costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion that reduced the adjusted basis of the property; or |
| • | the excess of: |
| • | the amount realized, in the case of a sale, exchange or involuntary conversion; or |
| • | the fair market value of the interest, in the case of any other taxable disposition; |
over the adjusted basis of the property. I.R.C. §1254(a).
(See “– Intangible Drilling Costs” and “– Depletion Allowance,” above.)
Also, all gain on the sale or other taxable disposition of equipment by the partnership will be treated as ordinary income to the extent of MACRS deductions previously claimed by the partnership. I.R.C. §1254(a). (See “– Depreciation and Cost Recovery Deductions,” above.)
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Disposition of Units
The sale or exchange, including a purchase by the managing general partner, of all or some of your units, if held by you as a capital asset for more than 12 months, will result in your recognition of long-term capital gain or loss, except for your share of your partnership’s “§751 assets” (i.e. inventory items and unrealized receivables). “Unrealized receivables” includes any right to payment for goods delivered, or to be delivered, to the extent the proceeds would be treated as amounts received from the sale or exchange of non-capital assets, services rendered or to be rendered, to the extent not previously includable in income under your partnership’s accounting methods, and deductions previously claimed by you for depreciation, depletion and intangible drilling costs with respect to the partnership in which you invest. “Inventory items” includes property properly includable in inventory and property held primarily for sale to customers in the ordinary course of business and any other property that would produce ordinary income if sold, including accounts receivable for goods and services. These tax items are sometimes referred to in this discussion as “§751 assets.” All of these tax items may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your units. (See “– Sale of the Properties,” above.)
If your units are held for 12 months or less, your gain or loss will be short-term gain or loss. Also, your pro rata share of your partnership’s liabilities, if any, as of the date of the sale or exchange, must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability to you greater than the cash proceeds, if any, received by you from the disposition of your units. In addition to gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other taxable disposition of his units will be characterized as portfolio income under the passive activity loss rules to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. Treas. Reg. §1.469-2T(e)(3). (See “– Limitations on Passive Activity Losses and Credits,” above.)
A gift of your units may result in federal and/or state income tax and gift tax liability to you. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. §1031(a)(2)(D). Other types of dispositions of your units may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner on the conversion of his investor general partner units to limited partner units so long as there is no change in his share of his partnership’s liabilities or §751 assets as a result of the conversion. Revenue Ruling 84-52, 1984-1 C.B. 157. In addition, if you sell or exchange all or some of your units you are required by the Code to notify your partnership within 30 days or by January 15 of the following year, if earlier. The partnership will then report to the IRS any information required by the IRS to be reported regarding the transfer of the units, including your share of your partnership’s §751 assets that are subject to recapture as ordinary income as discussed above.
If you die, or sell or exchange all of your units, the taxable year of your partnership will close with respect to you, but not the remaining investors, on the date of death, sale or exchange, and there will be a proration of partnership items for the partnership’s taxable year. If you sell less than all of your units, the partnership’s taxable year will not terminate with respect to you, but your proportionate share of the partnership’s items of income, gain, loss, deduction and credit will be determined by taking into account your varying interests in the partnership during the taxable year.
If you sell or exchange all or some of your units in the partnership in which you invest, you are required under §6050K of the Code to notify the partnership within 30 days or by January 15 of the following year, if earlier. After receiving the notice, the partnership must file a return with the IRS setting forth the name and address of both you, as the transferor, and the transferee, the fair market value of the portion of the partnership’s unrealized receivables and appreciated inventory (i.e., §751 assets) allocable to the units sold or exchanged by you (which is subject to recapture as ordinary income instead of capital gain as discussed above) and any other information as may be required by the IRS. The partnership also must provide each person whose name is set forth in the return a written statement showing the information set forth on the return.
You are urged to seek advice based on your particular circumstances from an independent tax advisor before any sale or other disposition of your units, including any purchase of your units by the managing general partner.
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Alternative Minimum Tax
With limited exceptions, under §55 of the Code you must pay an alternative minimum tax if it exceeds your regular federal income tax for the year. Alternative minimum taxable income (“AMTI”) is regular federal taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer’s AMTI in excess of the applicable exemption amount (as set forth below); and additional AMTI is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See “– Sale of the Properties,” above.) Exemption amounts for alternative minimum tax purposes are different from the regular tax personal exemptions, which are not allowed, and the types and amounts of itemized deductions allowed for minimum tax purposes are more limited than those allowed for regular tax purposes as discussed below.
For tax years beginning in 2006, the exemption amounts for individuals under the Tax Increase Prevention Act were the following amounts:
| • | married individuals filing jointly and surviving spouses, $62,550, less 25% of AMTI exceeding $150,000 (zero exemption when AMTI is $400,200); |
| • | unmarried individuals, $42,500, less 25% of AMTI exceeding $112,500 (zero exemption when AMTI is $282,500); and |
| • | married individuals filing separately, $31,275, less 25% of AMTI exceeding $75,000 (zero exemption when AMTI is $200,100). Also, AMTI of married individuals filing separately was increased by the lesser of $31,275 or 25% of the excess of AMTI (without regard to the exemption reduction) over $200,100. |
Unless Congress takes further action, for tax years beginning in 2007 the exemption amounts for individuals for alternative minimum tax purposes will be reduced substantially from those set forth above as follows: $45,000 for married individuals filing jointly and surviving spouses, $33,750 for single persons other than surviving spouses, and $22,500 for married individuals filing separately.
Code sections suspending losses, such as the rules concerning your “at risk” amount in the partnership, the amount of your passive activity losses from the partnership, and your basis in your units, are recomputed for alternative minimum tax purposes, and the amounts of the deductions that are suspended, or capital gains that are recaptured as ordinary income, may differ for regular income tax and alternative minimum tax purposes. Due to the inherently factual nature of these determinations and each investor’s different tax situation, special counsel is unable to express an opinion as to whether any investor will incur, or increase, his alternative minimum tax liability because of an investment in the partnership.
As of the date of this prospectus, the 2006 exemption amounts for the AMTI of a noncorporate taxpayer that were available for 2006 had not been extended to 2007. Thus, you are urged to seek advice from an independent tax advisor to determine whether changes to the alternative minimum tax laws have been made after the date of this prospectus.
Some of the principal adjustments to taxable income that are used to determine an individual’s AMTI include those summarized below:
| • | Depreciation deductions of the costs of the equipment placed in service in the wells (“Tangible Costs”) may not exceed deductions computed using the 150% declining balance method. These adjustments are discussed in greater detail below. (See “– Depreciation and Cost Recovery Deductions,” above.) |
| • | Miscellaneous itemized deductions are not allowed. |
| • | Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income. |
| • | State and local property taxes and income taxes, or, at the taxpayer’s election, state and local sales taxes, which are itemized and deducted for regular tax purposes, are not deductible. |
| • | Interest deductions are restricted. |
| • | The standard deduction and personal exemptions are not allowed. |
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| • | Only some types of operating losses are deductible. |
| • | Passive activity losses are computed differently. |
| • | Earlier recognition of income from incentive stock options may be required. |
The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include:
| • | excess intangible drilling costs, as discussed below; and |
| • | tax-exempt interest earned on certain private activity bonds, less any deductions that would have been allowable if the interest were included in gross income for regular income tax purposes. |
For taxpayers other than “integrated oil companies” as that term is defined in “– Intangible Drilling Costs,” above, which does not include the partnerships, the 1992 National Energy Bill repealed:
| • | the preference for excess intangible drilling costs; and |
| • | the excess percentage depletion preference for natural gas and oil. |
The repeal of the excess intangible drilling costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer’s AMTI computed as if the excess intangible drilling costs preference had not been repealed. I.R.C. §57(a)(2)(E). Under the prior rules, the amount of intangible drilling costs that is not deductible for alternative minimum tax purposes is the excess of the “excess intangible drilling costs” over 65% of net income from natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess intangible drilling costs. Excess intangible drilling costs is the regular intangible drilling costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer’s election, under the cost depletion method. There is no preference item for costs of nonproductive wells.
Also, you may elect under §59(e) of the Code to capitalize all or part of your share of your partnership’s intangible drilling costs (which does not include your share of the partnership’s intangible drilling costs of a re-entry well that are treated under the Code as operating costs, if any) and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the partnership. This election also applies for regular tax purposes and can be revoked only with the IRS’ consent. Making this election, therefore, will include the following principal consequences to you:
| • | your regular federal income tax deduction for intangible drilling costs in 2007 will be reduced because you must spread the deduction for the amount of intangible drilling costs which you elect to capitalize over the 60-month amortization period; and |
| • | the capitalized intangible drilling costs will not be treated as a preference that is included in your alternative minimum taxable income. |
Other than intangible drilling costs as discussed above, and passive activity losses and credits in the case of limited partners, the principal tax item that may have an impact on your alternative minimum taxable income as a result of investing in a partnership is depreciation of the partnership’s equipment expenses. (See “– Limitations on Passive Activity Losses and Credits,” above.) As noted in “– Depreciation and Cost Recovery Deductions,” above, each partnership’s cost recovery deductions for regular income tax purposes will be computed differently than for alternative minimum tax purposes. Consequently, in the early years of the cost recovery period of your partnership’s equipment, but not in the later years, your depreciation deductions from the partnership will be smaller for alternative minimum tax purposes than your depreciation deductions for regular income tax purposes on the same equipment. This could cause you to incur, or may increase, your alternative minimum tax liability in those taxable years. Conversely, this adjustment may decrease your alternative minimum taxable income in the later years of the cost recovery period. Also, under current law, your share of your partnership’s marginal well production credits, if any, may not be used to reduce your alternative minimum tax liability, if any. In addition, the rules relating to the alternative minimum tax for corporations are different from those for individuals that are discussed above.
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All prospective investors contemplating purchasing units in a partnership are urged to seek advice based on their particular circumstances from an independent tax advisor as to the likelihood of them incurring or increasing any alternative minimum tax liability as a result of an investment in a partnership.
Limitations on Deduction of Investment Interest
Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest expense deductions to subsequent taxable years. I.R.C. §163(d). An investor general partner’s share of any interest expense incurred by the partnership in which he invests before his investor general partner units are converted to limited partner units will be subject to the investment interest limitation. I.R.C. §163(d)(5)(A)(ii). In addition, an investor general partner’s share of the partnership’s loss in 2007 as a result of the deduction for intangible drilling costs will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expenses, if any, in 2007, with the disallowed portion to be carried forward to subsequent taxable years. This limitation on the deduction of investment interest expenses, however, will not apply to any income or expenses taken into account by limited partners in computing their income or loss from the partnership as a passive activity under §469 of the Code. I.R.C. §163(d)(4)(D). (See “– Limitations on Passive Activity Losses and Credits,” above.)
Allocations
The partnership agreement allocates to you your share of your partnership’s income, gains, losses, deductions, and credits, if any, including the deductions for intangible drilling costs and depreciation. Allocations under the partnership agreement of some tax items are made in ratios that are different from allocations of other tax items (i.e., “special allocations”). Your capital account in the partnership in which you invest will be adjusted to reflect your share of these allocations, and your capital account, as adjusted, will be given effect by the partnership in making distributions to you on liquidation of the partnership or your units. Also, the basis of the natural gas and oil properties owned by your partnership for purposes of computing cost depletion and gain or loss on disposition of a property will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See §5.03(b) of the Partnership Agreement.)
Your capital account in the partnership in which you invest will be:
| • | increased by the amount of money you contribute to the partnership and allocations of partnership income and gain to you; and |
| • | decreased by the value of property or cash distributed to you by the partnership and allocations of partnership losses and deductions to you. |
Allocations made in a manner that is disproportionate to the respective interests of the partners in a partnership of any item of partnership income, gain, loss, deduction or credit will not be given effect unless the allocation has “substantial economic effect.” I.R.C. §704(b). Economic effect means that if there is an economic benefit or burden that corresponds to an allocation, the partner to whom the allocation is made must receive the economic benefit or bear the economic burden. The economic effect of an allocation is substantial if there is a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences and taking into account the partners’ tax attributes that are unrelated to the partnership. The allocations under the partnership agreement will have economic effect if throughout the term of the partnership in which you invest:
| • | the partners’ capital accounts are increased and decreased as described above; |
| • | liquidation proceeds are distributed in accordance with the partners’ capital accounts; and |
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| • | any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the deficit to the partnership. |
Even though you and the other investors are not required under the partnership agreement to restore any deficit balance in your capital accounts in your partnership by making additional capital contributions to the partnership, an allocation that is not attributable to nonrecourse debt or tax credits will still be considered to have economic effect under the Treasury Regulations to the extent it does not cause or increase a deficit balance in your capital account if:
| • | the partners’ capital accounts are increased and decreased as described above; |
| • | the partnership’s liquidation proceeds are distributed in accordance with the partners’ capital accounts; and |
| • | the partnership agreement provides that if you unexpectedly incur a deficit balance in your capital account because of certain adjustments, allocations, or distributions of the partnership, then you will be allocated an additional amount of partnership income and gain that is sufficient to eliminate the deficit balance as quickly as possible. |
Treas. Reg. §1.704-1(b)(2)(ii)(d). These provisions are included in the partnership agreement (See §§5.02, 5.03(h), and 7.02(a) of the partnership agreement.)
Special provisions of the Treasury Regulations apply to deductions that are related to nonrecourse debt and tax credits, since allocations of those tax items cannot have substantial economic effect under the Treasury Regulations. If the managing general partner or an affiliate makes a nonrecourse loan to the partnership in which you invest (a “partner nonrecourse liability”), then that partnership’s losses, deductions, or §705(a)(2)(B) expenditures attributable to the loan must be allocated to the managing general partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the managing general partner must be allocated income and gain equal to the net decrease. (See §§5.03(a)(1) and 5.03(i) of the partnership agreement.) In addition, any marginal well production credits of the partnership will be allocated among the managing general partner and you and the other investors in the partnership in accordance with each partner’s respective interest in the partnership’s production revenues from the sale or its natural gas and oil production. (See §5.03(g) of the partnership agreement, “Participation in Costs and Revenues,” and “– Marginal Well Production Credits,” above.)
If you sell or transfer your unit in the partnership in which you invest, or on the death of an investor, or the admission of an additional partner, the partnership’s income, gain, loss, credits and deductions will be allocated among its partners according to their varying interests in the partnership during the taxable year. In addition, the Code may require the partnership’s property to be revalued on the admission of additional partners, if any, if disproportionate distributions are made to the partners, or if there are “built-in” losses on the transfer of a partner’s units or any distribution of the partnership’s property to its partners. (See “– Tax Elections,” below.)
It also should be noted that your share of items of income, gain, loss, deduction, and credit, if any, in the partnership in which you invest must be taken into account by you whether or not you receive any cash distributions from the partnership. For example, your share of partnership revenues applied by your partnership to the repayment of loans, if any, or the reserve for plugging wells, will be included in your gross income in a manner analogous to an actual distribution of the revenues (and income) to you. Thus, you may have tax liability on taxable income from your partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent a partnership has cash available for distribution, however, it is the managing general partner’s policy that partnership cash distributions to you and the other investors in that partnership will not be less than the managing general partner’s estimate of the investors’ income tax liability (as a group) with respect to that partnership’s income.
If any allocation under the partnership agreement is not recognized for federal income tax purposes, your share of the items subject to the allocation will be determined in accordance with your interest in the partnership in which you invest by considering all of the relevant facts and circumstances. To the extent deductions or credits allocated by the partnership agreement exceed deductions or credits which would be allowed under a reallocation of those tax items by the IRS, you may incur a greater tax burden.
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Partnership Borrowings
Under the partnership agreement, only the managing general partner and its affiliates may make loans to the partnerships. The use of partnership revenues taxable to you to repay borrowings by your partnership could create income tax liability for you in excess of your cash distributions from the partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide loans that will not be treated by the IRS as capital contributions to the partnership by the managing general partner or its affiliates in light of all of the surrounding facts and circumstances. Also, the “at risk” amounts of you and the other investors in the partnership in which you invest, which limit the amount of partnership losses you and the other investors can claim as discussed in “– ‘At Risk’ Limitation on Losses,” above, will not be increased by the amount of any partnership borrowings from the managing general partner or its affiliates, because you and the other investors will not bear any risk of repaying the borrowings from your non-partnership assets, even if you invest in the partnership as an investor general partner.
Partnership Organization and Offering Costs
Expenses connected with the offer and sale of units in a partnership, such as the dealer-manager fee, sales commissions, and other selling expenses, professional fees, and printing costs, which are charged under the partnership agreement 100% to the managing general partner as organization and offering costs, are not deductible. Although expenses incident to the creation of a partnership may be amortized over a period of not less than 180 months, these expenses also will be paid by the managing general partner as part of each partnership’s organization costs. Thus, any related deductions, which the managing general partner does not anticipate will be material in amount as compared to the total amount of subscription proceeds of each partnership, will be allocated under the partnership agreement to the managing general partner.
Tax Elections
Each partnership may elect to adjust the basis of its property (other than cash) on the transfer of a unit in the partnership by sale or exchange or on the death of an investor, and on the distribution of property (other than money) by the partnership to an investor (the §754 election). If the §754 election is made, the transferees of the units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the partnership assets and the partnership is treated for these purposes, on distributions to the investors, as though it had newly acquired an interest in the partnership assets and therefore acquired a new cost basis for the assets. Any election, once made, may not be revoked without the consent of the IRS.
In this regard, due to the complexities and added expense of the tax accounting required to implement a §754 election to adjust the basis of a partnership’s property when units are sold, taking into account the limitations on the sale of the partnership’s units as described in “Transferability of Units,” the managing general partner anticipates that the partnerships will not make the §754 election, although they reserve the right to do so. Even if the partnerships do not make the §754 election, however, the basis adjustment described above is mandatory under the Code with respect to the transferee partner only, if at the time a unit is transferred by sale or exchange, or on the death of an investor, a partnership’s adjusted basis in its property exceeds the fair market value of the property by more than $250,000 immediately after the transfer of the unit. Similarly, a basis adjustment is mandatory under the Code if a partnership distributes property in-kind to a partner and the sum of the partner’s loss on the distribution and the basis increase to the distributed property is more than $250,000. I.R.C. §§734 and 743. In this regard, under §7.02 of the partnership agreement, a partnership will not distribute its assets in-kind to its investors except to a liquidating trust or similar entity for the benefit of its investors on the dissolution and termination of the partnership, unless at the time of the distribution its investors have been offered the election of receiving in-kind property distributions, and you or any other investor in that partnership accepts the offer after being advised of the risks associated with direct ownership; or there are alternative arrangements in place which assure that you and the other investors in that partnership will not, at any time, be responsible for the operation or disposition of the partnership’s properties.
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If the basis of a partnership’s assets must be adjusted as discussed above, the primary effect on the partnership, other than the federal income tax consequences discussed above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. In this regard, the partnerships will not make in-kind property distributions to their respective investors except in the limited circumstances described above, and the units will have no readily available market and will be subject to substantial restrictions on their transfer. (See “Transferability of Units – Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.”) These factors will tend to reduce the likelihood that a partnership will be required to make mandatory basis adjustments to its properties.
In addition to the §754 election, each partnership may make various elections under the Code for federal tax reporting purposes that could result in the deductions of intangible drilling costs and depreciation, and the depletion allowance, being treated differently for tax purposes than for accounting purposes. Also, under §195 of the Code “start-up expenditures” may be capitalized and amortized over a 180-month period. The term “start-up expenditure” for this purpose includes any amount:
| • | paid or incurred in connection with: |
| • | investigating the creation or acquisition of an active trade or business; |
| • | creating an active trade or business; or |
| • | any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of that activity becoming an active trade or business; and |
| • | that would be allowable as a deduction if paid or incurred in connection with the expansion of an existing business. |
If it is ultimately determined by the IRS or the courts that any of a partnership’s expenses constituted start-up expenditures, that partnership’s deductions for those expenses, including your share, if any, of those deductions under the partnership agreement would be amortized over the 180-month period.
Tax Returns and IRS Audits
The tax treatment of most partnership items is determined at the partnership, rather than the partner level. Accordingly, you are required to treat the partnership’s tax items of the partnership in which you invest on your individual federal income tax returns in a manner that is consistent with the treatment of the partnership items on the partnership’s federal information income tax returns, unless you disclose to the IRS, by attaching the required IRS notice to your individual federal income tax return, that your tax treatment of the partnership’s tax items on your personal federal income tax returns is different from their partnership’s tax treatment of those partnership tax items. I.R.C. §§6221 and 6222. Treasury Regulations define partnership tax items for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg. §301.6231(a)(3)-1.
In most cases, the IRS must make an administrative determination as to partnership tax items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an IRS administrative determination with respect to the partnership before filing suit for any credit or refund. Also, the period for assessing tax against you and the other investors because of a partnership tax item may be extended by agreement between the IRS and the managing general partner, which will serve as each partnership’s representative (“Tax Matters Partner”) in all administrative tax proceedings and tax litigation, if any, conducted at the partnership level.
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The Tax Matters Partner may enter into a settlement on behalf of, and binding on, any investor owning less than a 1% profits interest in a partnership if there are more than 100 partners in the partnership, unless that investor timely files a statement with the Secretary of the Treasury providing that the Tax Matters Partner does not have authority to enter into a settlement agreement on behalf of that investor. Based on its past experience, the managing general partner anticipates that there will be more than 100 investors in each partnership in which units are offered for sale. However, by executing the Subscription Agreement you also are executing the partnership agreement if your Subscription Agreement is accepted by the managing general partner. Under the partnership agreement, you and the other investors in that partnership agree that you will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an “electing large partnership.” However, most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are applied at the partnership level and not the partner level. Thus, the managing general partner does not anticipate that the partnerships will make this election, although they reserve the right to do so.
All expenses of any tax proceedings involving a partnership and the managing general partner acting as Tax Matters Partner, which might be substantial, will be paid for by the partnership and not by the managing general partner from its own funds. The managing general partner, however, is not obligated to contest any adjustments made by the IRS to a partnership’s federal information income tax returns, even if the adjustment also would affect the individual federal income tax returns of you and the other investors in that partnership. The managing general partner will notify you and the other investors in your partnership of any IRS audits or other tax proceedings involving your partnership, and will provide you and the other investors any other information regarding the proceedings as may be required by the partnership agreement or law.
Tax Returns. Your individual income tax returns are your responsibility. Each partnership will provide its investors with the tax information applicable to their investment in the partnership necessary to prepare their tax returns.
Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions
Under §183 of the Code, your ability to deduct your share of your partnership’s deductions could be limited or lost if the partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if your partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the partnership deductions claimed by you would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear under the Treasury Regulations to be sufficient grounds for the denial of losses. Also, if a principal purpose of a partnership is to reduce substantially the partners’ federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized under Treasury Regulation §1.701-2 to remedy the abuse. Finally, under potentially relevant judicial doctrines such as the step transaction, business purpose, economic substance, substance over form, and sham transaction doctrines, tax deductions and tax credits from a transaction, including each partnership’s deduction for intangible drilling costs in 2007, would be disallowed if your partnership were found by the IRS or the courts, to have no economic substance apart from the tax benefits.
With respect to these issues, special counsel has given its opinions that the partnerships will possess the requisite profit motive, and the IRS anti-abuse rule in Treas. Reg. §1.701-2 and the potentially relevant judicial doctrines listed above will not have a material adverse effect on the tax consequences of an investment in a partnership by a typical investor as described in special counsel’s opinions. These opinions are based in part on the results of the previous partnerships sponsored by the managing general partner as set forth in “Prior Activities” and the managing general partner’s representations to special counsel, which are set forth in its tax opinion letter attached as Exhibit 8 to the Registration Statement of which this prospectus is a part. The managing general partner’s representations include that each partnership will be operated as described in this prospectus (see “Management” and “Proposed Activities”) and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis to its investors, apart from tax benefits, as described in this prospectus. Also, see the information concerning the partnerships’ proposed drilling areas in “Proposed Activities,” and the geological evaluations and other information for the specific prospects proposed to be drilled by Atlas Resources Public #16-2007(A) L.P. included in Appendix A to this prospectus, which represent a portion of the prospects to be drilled if that partnership’s targeted maximum subscription proceeds of $100 million are received (which is not binding on the partnership) as described in “Terms of the Offering – Subscription to a Partnership.” Also, the managing general partner has represented that Appendix A in this prospectus will be supplemented or amended to cover a portion of the specific prospects proposed to be drilled by Atlas Resources Public #16-2007(B) L.P. if units in that partnership are offered to prospective investors.
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Federal Interest and Tax Penalties
Taxpayers must pay tax and interest on underpayments of federal income taxes and the Code contains various penalties, including penalties for negligence and substantial valuation misstatements with respect to their individual federal income tax returns. In addition, there is a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. There is a substantial understatement by a noncorporate taxpayer if the correct income tax, as finally determined by the IRS or the courts, exceeds the income tax liability shown on the taxpayer’s federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation, or a personal holding company as defined in §542 of the Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the correct tax (or, if greater, $10,000); or (ii) $10 million). I.R.C. §6662. A noncorporate taxpayer may avoid this penalty if the understatement was not attributable to a “tax shelter,” as that term is defined below, and there is or was substantial authority for the taxpayer’s tax treatment of the item that caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer’s individual federal income tax return or a statement attached to the return and the taxpayer had a “reasonable basis” for the tax treatment of that item. In the case of an understatement that is attributable to a “tax shelter,” however, which may include each of the partnerships for this purpose, the penalty may be avoided by a non-corporate taxpayer only if there was reasonable cause for the underpayment and the taxpayer acted in good faith, or there is or was substantial authority for the taxpayer’s treatment of the item that caused the understatement, and the taxpayer reasonably believed that his or her treatment of the item on his individual federal income tax return was more likely than not the proper treatment.
For purposes of this penalty, the term “tax shelter” includes a partnership if a significant purpose of the partnership is the avoidance or evasion of federal income tax. Because the IRS has not explained what a “significant” purpose of avoiding or evading federal income taxes means, special counsel cannot give an opinion as to whether the partnerships are “tax shelters” as defined by the Code for purposes of this penalty.
Also, under §6662A of the Code, there is a 20% penalty for reportable transaction understatements of federal income taxes on a taxpayer’s individual federal income tax return for any tax year. However, if the disclosure rules for reportable transactions under the Code and the Treasury Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a “reasonable cause” exception to the penalty that is set forth in §6664(d) of the Code will not be available to the taxpayer. Under Treasury Regulation §1.6011-4, a taxpayer who participates in a reportable transaction in any taxable year must attach to his individual federal income tax return IRS Form 8886 “Reportable Transaction Disclosure Statement,” and file it with the IRS as directed in the Regulation, in order to comply with the disclosure rules.
A tax item is subject to the reportable transaction rules if the tax item is attributable to:
| • | any listed transaction, which is a transaction that is the same as, or substantially similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance transaction; or |
| • | any of four additional types of reportable transactions, if a significant purpose of the transaction is federal income tax avoidance or evasion. |
A “loss transaction” is one type of reportable transaction, but only if a “significant” purpose of the transaction is federal income tax avoidance or evasion. As set forth above, special counsel cannot give an opinion with respect to whether or not each partnership has a “significant” purpose of avoiding or evading federal income taxes, because the IRS has not explained what that phrase means for purposes of this penalty. Subject to the foregoing, under Treasury Regulation §1.6011-4(b)(5), there is a loss transaction if a partnership or any of its noncorporate partners claims a loss under §165 of the Code of at least $2 million, in the aggregate, in any taxable year of the partnership, or at least $4 million, in the aggregate, over the partnership’s first six years. In this regard, however, special counsel has given its opinion that the partnerships are not, and should not be in the future, reportable transactions under the Code.
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For purposes of the “loss transaction” rules, a §165 loss includes an amount deductible under a provision of the Code that treats a transaction as a sale or other disposition of property, or otherwise results in a deduction under §165. A §165 loss includes, for example, a loss resulting from a sale or exchange of a partnership interest, such as an investor’s units in a partnership. The amount of a §165 loss is adjusted for any salvage value and for any insurance or other compensation received. However, a §165 loss for this purpose does not take into account offsetting gains or other income limitations under the Code.
Each partnership will incur a tax loss in 2007 in excess of $2 million if the partnership receives subscription proceeds of approximately $2,225,000 or more, or a loss in excess of $4 million if subscription proceeds of at least $4,450,000 are received by the partnership, due primarily to the amount of intangible drilling costs for productive wells that each partnership intends to claim as a deduction. Notwithstanding the foregoing, in special counsel’s opinion the partnerships’ losses resulting from deductions claimed for intangible drilling costs for productive wells properly should be treated as losses under §263(c) of the Code and Treas. Reg. §1.612-4(a), and should not be treated as §165 losses for purposes of the “loss transaction” rules under Treas. Reg. 1.6011-4(b)(5). However, the partnerships may incur losses under §165 of the Code, such as losses for the abandonment by a partnership of:
| • | wells drilled that are nonproductive (i.e. a “dry hole”), if any, in which case the intangible drilling costs, the tangible costs, and possibly the lease acquisition costs of the abandoned wells would be deducted as §165 losses; and |
| • | wells that have been operated until their commercial natural gas and oil reserves have been depleted, in which case the undepreciated tangible costs, if any, and possibly the lease acquisition costs, would be deducted as §165 losses. |
In this regard, based primarily on its past experience (as shown in “Prior Activities”), including Atlas America’s 97% completion rate for wells drilled by its previous development drilling partnerships in the Appalachian Basin (see “– Management”), the managing general partner has represented the following:
| | • | when a well is plugged and abandoned by a partnership, the salvage value of the well’s equipment usually will cover a substantial amount of the costs of abandoning and reclaiming the well site; |
| • | each partnership will drill relatively few non-productive wells (i.e., “dry holes”), if any; |
| • | each productive well drilled by a partnership will have a different productive life and the wells will not all be depleted and abandoned in the same taxable year; |
| • | each productive well drilled by a partnership will produce for more than six years; and |
| • | approximately 389 gross wells (which is approximately 355) net wells will be drilled by Atlas Resources Public #16-2007(A) L.P. if its targeted maximum subscription proceeds of $100 million are received, based on the managing general partner’s estimate of the average weighted cost of drilling and completing the partnership’s wells. (See “Compensation – Drilling Contracts). |
State and Local Taxes
Each partnership will operate in states and localities that may impose a tax on it, or on you and the partnership’s other investors, based on the partnership’s assets or income or your share of its assets or income. Because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon your partnership as an entity, the cash available for distribution to you would be reduced. Each partnership also may be subject to state income tax withholding requirements on its income allocable to you and its other investors, whether or not the revenues that created the income are distributed to you and its other investors. Deductions and credits, including federal marginal well production credits, if any, which may be available to you for federal income tax purposes, may not be available to you for state or local income tax purposes. If you reside in a state or locality that imposes income taxes on its residents, you likely will be required under those income tax laws to include your share of your partnership’s net income or net loss in determining your reportable income for state or local tax purposes in the jurisdiction in which you reside. To the extent that you pay tax to another state because of partnership operations within that state, you may be entitled to a deduction or credit against tax owed to your state of residence with respect to the same income. Also, due to a partnership’s operations in a state or local jurisdiction, state or local estate or inheritance taxes may be payable on the death of an investor in addition to taxes imposed by his own domicile.
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Each partnership’s units may be sold in all 50 states and the District of Columbia and other jurisdictions, and it is not practical for special counsel to evaluate the many different state and local tax laws that may affect one or more of a partnership’s investors with respect to their investment in the partnership. You are urged to seek advice based on your particular circumstances from an independent tax advisor to determine the effect state and local taxes, including gift and death taxes as well as income taxes, may have on you in connection with an investment in a partnership.
Severance and Ad Valorem (Real Estate) Taxes
Each partnership will incur various ad valorem or severance taxes imposed by state or local taxing authorities on its natural gas and oil wells and/or natural gas and oil production from the wells. These taxes will reduce the amount of each partnership’s cash available for distribution to you and its other investors.
Social Security Benefits and Self-Employment Tax
A limited partner’s share of income or loss from a partnership is excluded from the definition of “net earnings from self-employment.” No increased benefits under the Social Security Act will be earned by limited partners and if any limited partners are currently receiving Social Security benefits, their shares of partnership taxable income will not be taken into account in determining any reduction in benefits because of “excess earnings.”
An investor general partner’s share of income or loss from a partnership will constitute “net earnings from self-employment” for these purposes. The ceiling for social security tax of 12.4% in 2007 is $97,500, which will be adjusted annually for inflation in 2008 and subsequent years. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax.
Farmouts
Under a farmout by a partnership, if a property interest, other than an interest in the drilling unit assigned to the partnership well in question, is earned by the farmee (anyone other than the partnership) from the farmor (the partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor’s tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The managing general partner has represented that it will attempt to eliminate or reduce any gain to a partnership from a farmout, if any. However, if the IRS claims that a farmout by a partnership results in taxable income to the partnership and its position is ultimately sustained, you and the other investors in that partnership would be required to include your share of the resulting taxable income on your individual income tax returns, even though the partnership and you and the other investors in that partnership received no cash from the farmout.
Foreign Partners
Each partnership will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to partnership income allocable to its foreign investors, even if no cash distributions are made to them. In the event of overwithholding, a foreign investor must seek a refund on his individual United States federal income tax return. For withholding purposes, a foreign investor means an investor who is not a United States person and includes a nonresident alien individual, a foreign corporation, a foreign partnership, and a foreign trust or estate, unless the investor has certified to his partnership the investor’s status as a U.S. person on Form W-9 or any other form permitted by the IRS for that purpose.
Foreign investors are urged to seek advice based on their particular circumstances from an independent tax advisor regarding the applicability of these rules and the other tax consequences of an investment in a partnership to them.
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Estate and Gift Taxation
There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion amount was $12,000 per donee in 2007, which will be adjusted in 2008 and subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 (the “2001 Tax Act”), the maximum estate and gift tax rate is 45% from 2007 through 2009. Estates of $2.0 million or less in 2007, which increases to estates of $3.5 million or less in 2009, are not subject to federal estate tax to the extent those exemption amounts (i.e., unified credit amounts) were not previously used by the decedent to reduce gift taxes on any lifetime gifts in excess of the applicable annual exclusion amount for gifts. Under the 2001 Tax Act, the federal estate tax will be repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011, however, the federal estate and gift taxes are scheduled to be reinstated under the rules in effect before the 2001 Tax Act was enacted, which would, among other things, reduce the unified credit amount and increase the tax rates.
Changes in the Law
Your tax benefits from an investment in a partnership may be affected by changes in the tax laws. For example, in 2003 the top four federal income tax brackets for individuals were reduced through December 31, 2010, including reducing the top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to some degree the amount of taxes you can save by virtue of your share of your partnership’s deductions for intangible drilling costs, depletion and depreciation, and marginal well production credits, if any. On the other hand, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by you on your share of your partnership’s net income. However, the federal income tax brackets discussed above could be changed again, even before 2011, and other changes in the tax laws could be made which would affect your tax benefits from an investment in a partnership.
You are urged to seek advice based on your particular circumstances from an independent tax advisor with respect to the impact of recent federal tax legislation on an investment in a partnership and the status of federal and state legislative, regulatory or administrative tax developments and tax proposals and their potential effect on the tax consequences to you of an investment in a partnership.
SUMMARY OF PARTNERSHIP AGREEMENT
The rights and obligations of the managing general partner and you and the other investors in a partnership are governed by the form of partnership agreement, a copy of which attached as Exhibit (A) to this prospectus. You are urged to thoroughly review the partnership agreement before you decide to invest in a partnership. The following is a summary of the material provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the partnership agreement.
Liability of Limited Partners
Each partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you invest as a limited partner, then generally you will not be liable to third-parties for the obligations of your partnership unless you:
| • | also invest as an investor general partner; |
| • | take part in the control of the partnership’s business in addition to the exercise of your rights and powers as a limited partner; or |
| • | fail to make a required capital contribution to the extent of the required capital contribution. |
In addition, you may be required to return any distribution you receive from a partnership if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent.
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Amendments
Amendments to the partnership agreement of a partnership may be proposed in writing by:
| | • | the managing general partner and adopted with the consent of investors whose units equal a majority of the total units in the partnership; or |
| • | investors whose units equal 10% or more of the total units in the partnership and adopted by an affirmative vote of investors whose units equal a majority of the total units in the partnership. |
The partnership agreement of each partnership may also be amended by the managing general partner without the consent of the investors for certain limited purposes. However, an amendment that materially and adversely affects the investors can only be made with the consent of the affected investors. For example, an amendment may not increase the duties or liabilities of the investors, decrease the duties or liabilities of the managing general partner, decrease the investors’ profit sharing interest, or increase the investors’ loss sharing interest, increase the required capital contribution of the investors or decrease the required capital contribution of the managing general partner without the approval of the investors, and any amendment may not affect the classification of partnership income and loss for federal income tax purposes without the unanimous approval of all investors.
Notice
The following provisions apply regarding notices:
| | • | when the managing general partner gives you and other investors notice it begins to run from the date of mailing the notice and is binding even if it is not received; |
| • | the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and |
| • | if you fail to respond in the specified time to the managing general partner’s second request for approval of or concurrence in a proposed action, then you will conclusively be deemed to have approved the action unless the partnership agreement expressly requires your affirmative approval. |
Voting Rights
Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. At any time, however, investors whose units equal 10% or more of the total units in a partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of the managing general partner. On the matters being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction of one vote equal to the fractional interest in the unit. Investors whose units equal a majority of the total units in a partnership may vote to:
| • | dissolve the partnership; |
| • | remove the managing general partner and elect a new managing general partner; |
| • | elect a new managing general partner if the 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 the partnership’s assets; |
| • | cancel any contract for services with the managing general partner, the operator, or their affiliates without penalty on 60 days notice; and |
| • | amend the partnership agreement, however, any amendment may not: |
| • | without the approval of you or the managing general partner increase the duties or liabilities of you or the managing general partner, or increase or decrease the profits or losses or required capital contribution of you or the managing general partner; or |
| • | without the unanimous approval of all investors in the partnership, affect the classification of partnership income and loss for federal income tax purposes. |
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The managing general partner, its officers, directors, and affiliates may also subscribe for units in each partnership on a discounted basis, and they may vote on all matters, including the issues set forth above, other than:
| • | removing the managing general partner and operator; and |
| • | any transaction between the managing general partner or its affiliates and the partnership. |
Any units owned by the managing general partner and its affiliates will not be included in determining the requisite number of units necessary to approve any partnership matter on which the managing general partner and its affiliates may not vote or consent.
Access to Records
You will have access to all records of your partnership at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Also, your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement.
Withdrawal of Managing General Partner
After 10 years the managing general partner may voluntarily withdraw as managing general partner of a partnership for any reason by giving 120 days’ written notice to you and the other investors in the partnership. Although the 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 investors whose units equal a majority of the total units in the partnership. If the investors, however, choose not to continue the partnership and do not select a substitute managing general partner, then the partnership would dissolve and terminate, which could result in adverse tax and other consequences to you.
Also, the managing general partner may assign its general partner interest in the partnership to its affiliates, and it may withdraw a property interest in the form of a working interest in the partnership’s wells equal to or less than its revenue interest at any time if the withdrawal is:
| • | to satisfy the bona fide request of its creditors; or |
| • | approved by investors in the partnership whose units equal a majority of the total units. |
(See “Management – Managing General Partner and Operator” and “Conflicts of Interest – Conflicts Regarding the Managing General Partner Withdrawing or Assigning an Interest.”
Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months
Although the managing general partner anticipates that each partnership will spend all of its subscription proceeds soon after the offering of the partnership closes, each partnership will have 12 months in which to use or commit its subscription proceeds to drilling activities. If within the 12-month period the partnership has not used, or committed for use, all of its subscription proceeds, then the managing general partner will distribute the remaining subscription proceeds to you and the other investors in the partnership in accordance with your respective subscription amounts as a return of capital.
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SUMMARY OF DRILLING AND OPERATING AGREEMENT
The managing general partner will serve as the operator under the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on 60 days’ advance written notice by the managing general partner acting on behalf of a partnership on the affirmative vote of investors whose units equal a majority of the total units in the partnership. You are urged to thoroughly review the drilling and operating agreement before you decide to invest in a partnership. The following is a summary of the material provisions of the drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the drilling and operating agreement.
The drilling and operating agreement includes the material provisions set forth below.
| • | The operator’s right to resign after five years. |
| • | The operator’s right beginning one year after a partnership well begins producing to retain $200 per month to cover future plugging and abandonment costs of the well. |
| • | The grant of a first lien and security interest in the wells and related production to secure payment of amounts due to the operator by a partnership. |
| • | The prescribed insurance coverage to be maintained by the operator. |
| • | Limitations on the operator’s authority to incur extraordinary costs with respect to producing wells in excess of $5,000 per well. |
| • | Restrictions on the partnership’s ability to transfer its interest in fewer than all wells unless the transfer is of an equal undivided interest in all of the wells. |
| • | The limitation of the operator’s liability to a partnership under section 4.05 of partnership agreement; |
| • | The excuse for nonperformance by the operator due to force majeure which generally means acts of God, catastrophes and other causes which preclude the operator’s performance and are beyond its control. |
REPORTS TO INVESTORS
Under the partnership agreement for each partnership you and certain state securities commissions will be provided the reports and information set forth below for your partnership, which your partnership will pay as a direct cost.
| • | Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing at least the following information. |
| • | Audited financial statements of the partnership prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation for information furnished for income tax purposes. Independent certified public accountants will audit the financial statements to be included in the annual report, but semiannual reports will not be audited. |
| • | A summary of the total fees and compensation paid by the partnership to the managing general partner, the operator, and their affiliates. In this regard, the independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described in §4.04(a)(2)(c) of the partnership agreement and that the total amount of costs allocated did not materially exceed the amounts actually incurred by the managing general partner. |
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If the managing general partner subsequently decides to allocate expenses in a manner different from that described in §4.04(a)(2)(c) of the partnership agreement, then the change must be reported to you and the other investors with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method.
| • | A description of each prospect owned by the partnership, including the cost, location, number of acres, and the interest. |
| • | A list of the wells drilled or abandoned by the partnership indicating: |
| • | whether each of the wells has or has not been completed; and |
| • | a statement of the cost of each well completed or abandoned. |
| • | A description of all farmouts, farmins, and joint ventures. |
| • | the total partnership costs; |
| • | the costs paid by the managing general partner and the costs paid by the investors; |
| • | the total partnership revenues; and |
| • | the revenues received or credited to the managing general partner and the revenues received or credited to you and the other investors. |
| • | On request the managing general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information is available at the SEC website www.sec.gov. |
| • | By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns. |
| • | Beginning with the second calendar year after your partnership closes, and every year thereafter, you will receive a computation of the partnership’s total natural gas and oil proved reserves and its dollar value. The reserve computations will be based on engineering reports prepared by the managing general partner and reviewed by an independent expert. |
PRESENTMENT FEATURE
Beginning with the fifth calendar year after your partnership closes, you and the other investors in your partnership may present your units to the managing general partner to purchase your units. However, you are not required to offer your units to the managing general partner, and you may receive a greater return if you retain your units. The managing general partner will not purchase less than one unit unless the fractional unit represents your entire interest in the partnership.
The managing general partner has no obligation or intention to establish a reserve to satisfy the presentment feature and it may immediately suspend the presentment obligation by notice to you if it determines, in its sole discretion, that it:
| • | does not have the necessary cash flow; or |
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| • | cannot borrow funds for this purpose on terms it deems reasonable. |
If fewer than all units presented at any time are to be purchased by the managing general partner, then the units to be purchased will be selected by lot.
The managing general partner’s obligation to purchase the units presented may be discharged for its benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the party who pays for it, and you will be required to deliver an executed assignment of your unit along with any other documents that the managing general partner requests. Your presentment of your units to the managing general partner for purchase is subject to the following conditions:
| • | the managing general partner will not purchase more than 5% of the total outstanding units in a partnership in any calendar year; |
| • | your presentment request must be made within 120 days of the partnership reserve report discussed below; |
| • | in accordance with Treas. Reg. §1.7704-1(f) the managing general partner may not purchase your units until at least 60 calendar days after you notify the partnership in writing of your intent to present your units for purchase; and |
| • | the purchase of your units will not be considered effective until the presentment price has been paid to you in cash. |
The amount of the presentment price for your units that is attributable to a partnership’s natural gas and oil reserves, as discussed below, will be determined based on the last reserve report prepared by the managing general partner and reviewed by an independent expert. Beginning with the second calendar year after your partnership closes and every year thereafter, the managing general partner will estimate the present worth of future net revenues attributable to your partnership’s interest in proved reserves. In making this estimate, the managing general partner will use:
| • | a constant oil price; and |
| • | base natural gas prices on the existing natural gas contracts at the time of the presentment. |
Your presentment price will be based on your share of your partnership’s net assets and liabilities as described below, based on the ratio that your number of units bears to the total number of units in your partnership. 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 the proved reserves determined as described above; |
| • | 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 |
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| • | any distributions made to you between the date of your presentment request and the date the presentment price is paid to you. However, if any cash distributed to you by the partnership, after your presentment request was derived from the sale of oil, natural gas, or a producing property the amount of those cash distributions will be discounted at the same rate used to take into account the risk factors employed to determine the present worth of the partnership’s proved reserves for purposes of determining the reduction of the presentment price. |
The presentment price may be further adjusted by the managing general partner for estimated changes from the date of the reserve report discussed above to the date of payment of the presentment price to you due to the following:
| • | the production or sales of, or additions to, reserves and lease and well equipment, sale or abandonment of leases, and similar matters occurring before the presentment request; and |
| • | any of the following occurring before payment of the presentment price to you; |
| • | changes in well performance; |
| • | increases or decreases in the market price of oil, natural gas, or other minerals; |
| • | revision of regulations relating to the importing of hydrocarbons; and |
| • | changes in income, ad valorem, and other tax laws such as material variations in the provisions for depletion; and |
As of September 15 2006, approximately 230 units have been presented to the managing general partner for purchase in its previous 53 limited partnerships.
TRANSFERABILITY OF UNITS
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement
Your ability to sell or otherwise transfer your units in your partnership is restricted by the securities laws, the tax laws, and the partnership agreement as described below. Also, the sale or other transfer of your units may create negative tax consequences to you as described in “Federal Income Tax Consequences – Disposition of Units.”
First, due to the tax laws, the partnership agreement provides that you will not be able to sell, assign, exchange, or transfer your unit if it would, in the opinion of counsel for the partnership, result in the following:
| • | the termination of your partnership for tax purposes; or |
| • | your partnership being treated as a “publicly traded” partnership for tax purposes. |
Second, under the partnership agreement sales or other transfers of the units are subject to the following additional limitations:
| • | except as provided by operation of law, the partnership will recognize the transfer of only one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be transferred; |
| • | the costs and expenses associated with the transfer must be paid by the person transferring the unit; |
| • | the form of transfer must be in a form satisfactory to the managing general partner; and |
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| • | the terms of the transfer must not contravene those of the partnership agreement. |
Your transfer of a unit will not:
| • | relieve you of your responsibility for any obligations related to your units under the partnership agreement; |
| • | grant rights under the partnership agreement as among your transferees, to more than one party unanimously designated by the transferees to the managing general partner; nor |
| • | require an accounting of the partnership by the managing general partner. |
If the assignee of the unit does not become a substituted partner as described below in “– Conditions to Becoming a Substitute Partner,” the transfer will be effective as of midnight of the last day of the calendar month in which it is made or, at the managing general partner’s election, 7:00 A.M. of the following day.
Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer your unit if the managing general partner requires, in its sole discretion, that you must provide an opinion of counsel acceptable to the managing general partner that the registration and qualification under any applicable federal or state securities laws are not required.
Conditions to Becoming a Substitute Partner
An assignee of a unit will not be entitled to any of the rights granted to a partner under the partnership agreement, other than the right to receive all or part of the share of the profits, losses, income, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled, unless the assignee becomes a substituted partner in accordance with the provisions set forth below. The conditions to become a substitute partner are as follows:
| • | the assignor gives the assignee the right; |
| • | the assignee pays all costs and expenses incurred in connection with the substitution; and |
| • | the assignee executes and delivers, in a form acceptable to the managing general partner, the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all of the terms and provisions of the partnership agreement. |
A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. Each partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners.
PLAN OF DISTRIBUTION
Commissions
The units in each partnership will be offered on a “best efforts” basis by Anthem Securities, which is an affiliate of the managing general partner, acting as dealer-manager and by other selected registered broker/dealers that are members of the NASD acting as selling agents. Anthem Securities was formed for the purpose of serving as dealer-manager of partnerships sponsored by the managing general partner and became an NASD member firm in April, 1997.
The dealer-manager will manage and oversee the offering of the units as described above. Best efforts generally means that the dealer-manager and selling agents will not guarantee that a certain number of units will be sold. Units may also be sold by the officers and directors of the managing general partner, other than those individuals who are associated persons of Anthem Securities, in those states where they are licensed to do so or are exempt from licensing. All offers and sales of units by the managing general partner’s officers and directors who are not associated persons of Anthem Securities will be made under the SEC safe harbor from broker/dealer registration provided by Rule 3a4-1. In this regard, none of the officers and directors of the managing general partner who may offer and sell units:
| • | is subject to a statutory disqualification, as that term is defined in Section 3(a)(39) of the Act, at the time of his participation; |
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| • | is compensated in connection with his participation by the payment of commissions or other remuneration based either directly or indirectly on transactions in securities; and |
| • | is at the time of his participation an associated person of a broker or dealer. |
Also, each of the officers and directors who may offer and sell units:
| • | performs, or is intended primarily to perform at the end of the offering, substantial duties for or on behalf of the managing general partner otherwise than in connection with transactions in securities; |
| • | was not a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months; and |
| • | will not participate in selling an offering of securities for any issuer more than once every 12 months, with the understanding that for securities issued pursuant to Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of any security included within one Rule 415 registration. |
Subject to the exceptions described below, the dealer-manager will receive on each unit sold:
| • | a 2.5% dealer-manager fee; |
| • | a 7% sales commission; and |
| • | an up to .5% reimbursement of the selling agent’s bona fide due diligence expenses. |
All of the reimbursement of the selling agents’ bona fide due diligence expenses and generally all of the 7% sales commission will be reallowed by the dealer-manager to the selling agents. With respect to the up to .5% reimbursement of a selling agent’s bona fide due diligence expenses, any bill presented by a selling agent to the dealer-manager for reimbursement of costs associated with its due diligence activities must be for actual costs, including overhead, incurred by the selling agent and may not include a profit margin. It is the responsibility of the managing general partner and the dealer-manager to ensure compliance with the above guideline. If the selling agent provides the dealer-manager an itemized bill for actual due diligence expenses which is in excess of .5%, then the excess over .5% will not be included within the 10% compensation guideline, but instead will be included within the 4.5% organization and offering cost guideline under NASD Conduct Rule 2810.
From the 2.5% dealer-manager fee, the dealer-manager may pay up to a .5% marketing fee if the selling agent meets certain sales thresholds and provides marketing support. Additionally, the Dealer-Manager may use a portion of its Dealer-Manager fee to pay for permissible non-cash compensation. Under Rule 2810 of the NASD Conduct Rules, non-cash compensation means any form of compensation received in connection with the sale of the units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. Permissible non-cash compensation includes the following:
| • | an accountable reimbursement for training and education meetings for associated persons of the selling agents; |
| • | gifts that do not exceed $100 per year and are not preconditioned on achievement of a sales target; |
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| • | an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target; and |
| • | contributions to a non-cash compensation arrangement between a selling agent and its associated persons, provided that neither the managing general partner nor the dealer-manager directly or indirectly participates in the selling agent’s organization of a permissible non-cash compensation arrangement. |
In no event shall a selling agent receive non-cash compensation and the marketing fee if it represents more than .5% per unit.
The managing general partner is also using the services of wholesalers who are employed by it or its affiliates and are registered through Anthem Securities. The wholesalers include four Regional Marketing Directors. A portion of the 2.5% dealer-manager fee will be reallowed to the affiliated wholesalers for subscriptions obtained through their efforts and their reimbursement of expenses. The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the wholesalers or as described in the prior paragraph.
The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules and all compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the source, will be limited to 10% of the gross proceeds of the offering plus the .5% reimbursement for bona fide due diligence expenses on each subscription. Also, the offering will be made in compliance with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and wholesalers will not execute a transaction for the purchase of units in a discretionary account without the prior written approval of the transaction by the customer. Finally, the offering will be conducted in compliance with SEC Rule 15c2-4.
Subject to the following, you and the other investors will pay $10,000 per unit and generally will share costs, revenues, and distributions in the partnership in which you invest in proportion to your respective number of units. However, the subscription price for certain investors will be reduced as set forth below:
| • | the subscription price for the managing general partner, its officers, directors, and affiliates, and investors who buy units through the officers and directors of the managing general partner, will be reduced by an amount equal to the 2.5% dealer-manager fee, the 7% sales commission and the .5% reimbursement for bona fide due diligence expenses, which will not be paid with respect to these sales; and |
| • | the subscription price for registered investment advisors and their clients, and selling agents and their registered representatives and principals, will be reduced by an amount equal to the 7% sales commission, which will not be paid with respect to these sales. |
No more than 5% of the total units in each partnership may be sold with the discounts described above. These investors who pay a reduced price for their units generally will share in a partnership’s costs, revenues, and distributions on the same basis as the other investors who pay $10,000 per unit as discussed in “Participation in Costs and Revenues – Allocation and Adjustments Among Investors.” Although the managing general partner and its affiliates may buy up to 5% of the units, they do not currently anticipate buying any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for a partnership to begin operations.
To help assure an orderly market for the units, the managing general partner, the dealer-manager and the selling agents may use such methods as they deem appropriate to allocate units among interested investors if they anticipate that demand for units will exceed the available supply, provided that no changes to compensation may be made. These methods may include, but will not be limited to:
| • | allocations of units to selling agents; |
| • | priority acceptance of subscriptions from previous investors in partnerships sponsored by the managing general partner; |
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| • | priority treatment for investors whose subscriptions were declined by earlier partnerships sponsored by the managing general partner because the number of units available was not sufficient to accommodate their subscriptions; or |
| • | any other methods as may be approved by the managing general partner. |
After the minimum subscription proceeds are received in a partnership and the checks have cleared the banking system, the dealer-manager fee and the sales commissions will be paid to the dealer-manager and selling agents approximately every two weeks until the offering closes.
Indemnification
The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees will be deemed underwriting compensation. The managing general partner and the dealer-manager have agreed to indemnify each other, and it is anticipated that the dealer-manager and each selling agent will agree to indemnify each other against certain liabilities, including liabilities under the 1933 Act.
SALES MATERIAL
In addition to the prospectus, the managing general partner intends to use the following sales material with the offering of the units:
| • | a flyer entitled “Atlas Resources Public #16-2007 Program”; |
| • | an article entitled “Tax Rewards with Oil and Gas Partnerships”; |
| • | a brochure of tax scenarios entitled “How an Investment in Atlas Resources Public #16-2007 Program Can Help Achieve an Investor’s Tax Objectives”; |
| • | a booklet entitled “Outline of Tax Consequences of Oil and Gas Drilling Programs”; |
| • | a brochure entitled “Investment Insights – Tax Time”; |
| • | a brochure entitled “Frequently Asked Questions”; |
| • | a brochure entitled “The Drilling Process”; and |
| • | possibly other supplementary materials. |
The managing general partner has not authorized the use of other sales material and the offering of units is made only by means of this prospectus. The sales material is subject to the following considerations:
| • | it must be preceded or accompanied by this prospectus; |
| • | it does not contain any information which is inconsistent with this prospectus; and |
| • | it should not be considered a part of or incorporated into this prospectus or the registration statement of which this prospectus is a part. |
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In addition, supplementary materials, including prepared presentations for group meetings, must be submitted to the state administrators before they are used and their use must either be preceded by or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to, “seminars” or other group meetings at which the units are to be described, offered, or sold will clearly indicate the following:
| • | that the purpose of the meeting is to offer the units for sale; |
| • | the minimum purchase price of the units; |
| • | the suitability standards to be employed; and |
| • | the name of the person selling the units. |
Also, no cash, merchandise, or other items of value may be offered as an inducement to you or any other prospective investor to attend the meeting. All written or prepared audiovisual presentations, including scripts prepared in advance for oral presentations to be made at the meetings, must be submitted to the state administrators within a prescribed review period. These provisions, however, will not apply to meetings consisting only of the registered representatives of the selling agents.
You should rely only on the information contained in this prospectus in making your investment decision. No one is authorized to provide you with information that is different.
LEGAL OPINIONS
Kunzman & Bollinger, Inc., has issued its opinion to the managing general partner regarding the validity and due issuance of the units, including assessibility, and its opinion on the material and any significant federal tax issues involving individual typical investors in the partnerships. However, the factual statements in this prospectus are those of the partnerships or the managing general partner, and counsel has not given any opinions with respect to any of the tax or other legal aspects of this offering except as expressly set forth above.
EXPERTS
The financial statements included in this prospectus for Atlas Resources, LLC, the managing general partner, as of and for the years ended September 30, 2005 and 2004 and the balance sheet for Atlas Resources Public #16-2007(A) L.P. have been audited by Grant Thornton LLP, as of the dates indicated in its reports which appear elsewhere in this prospectus. These financial statements have been included in this prospectus in reliance on the reports of Grant Thornton LLP on the authority of that firm as an expert in accounting and auditing.
The information concerning the estimated future net cash flows from proved reserves presented under “Prior Activities – Table 3 Investor Operating Results-Including Expenses” was prepared by Wright & Company, Inc., Brentwood, Tennessee, independent petroleum consultants, which is not affiliated with the managing general partner or its affiliates, and is included in this prospectus in reliance on Wright & Company, Inc. as an expert in petroleum consulting.
The geologic evaluations of United Energy Development Consultants, Inc., which is not affiliated with the managing general partner or its affiliates, appearing elsewhere in this prospectus have been included in this prospectus on the authority of United Energy Development Consultants, Inc. as an expert with respect to the matters covered by the evaluations and in the giving of the evaluations.
LITIGATION
The managing general partner knows of no litigation pending or threatened to which the managing general partner or the partnerships are subject or may be a party, which it believes would have a material adverse effect on the partnerships or their business, and no such proceedings are known to be contemplated by governmental authorities or other parties.
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FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL
PARTNER AND ATLAS RESOURCES PUBLIC #16-2007(A) L.P.
Financial information concerning the managing general partner and the second partnership in the program, Atlas Resources Public #16-2007(A) L.P., is reflected in the following financial statements. With respect to the managing general partner’s financial information, the managing general partner was changed from a corporation to a limited liability company in March, 2006. (See “Management – Managing General Partner and Operator.”)
The securities offered by this prospectus are not securities of, nor are you acquiring an interest in the managing general partner, its affiliates, or any other entity other than the partnership in which you purchase units.
INDEX TO FINANCIAL STATEMENTS
ATLAS RESOURCES PUBLIC #16-2007(A) L.P. FINANCIAL STATEMENTS | |
Report of Independent Registered Public Accounting Firm dated October 6, 2006 | F-1 |
Balance Sheet as of September 30, 2006 | F-2 |
Notes to Financial Statement dated September 30, 2006 | F-3 |
ATLAS RESOURCES, LLC AND SUBSIDIARY CONSOLIDATED FINANCIAL STATEMENTS | |
Report of Independent Registered Public Accounting Firm dated January 6, 2006 (except for Note 10, as to which the date is April 7, 2006) | F-8 |
Atlas Resources, LLC and Subsidiary Consolidated Balance Sheets | F-9 |
Atlas Resources, LLC and Subsidiary Consolidated Statements of Income | F-10 |
Atlas Resources, LLC and Subsidiary Consolidated Statements of Changes in Member’s Equity (Unaudited) | F-11 |
Atlas Resources, LLC and Subsidiary Consolidated Statements of Cash Flows | F-12 |
Atlas Resources, LLC and Subsidiary Consolidated Statements of Comprehensive Income | F-13 |
Atlas Resources, LLC and Subsidiary Notes to Consolidated Financial Statements dated as of September 30, 2006 (Unaudited) | F-14 |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners
Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
We have audited the accompanying balance sheet of Atlas Resources Public 16-2007 (A) L.P. (A Delaware Limited Partnership) formerly known as (“Atlas America Public 16-2007(A) L.P.”) as of September 30, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement 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 statement referred to above presents fairly, in all material respects, the financial position of Atlas Resources Public 16-2007 (A) L.P. as of September 30, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
October 6, 2006
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
BALANCE SHEET
September 30, 2006
ASSETS
PARTNER’S CAPITAL
The accompanying notes to financial statement are an integral part of this statement.
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT
September 30, 2006
1. | ORGANIZATION AND DESCRIPTION OF BUSINESS |
Atlas Resources Public 16-2007 (A) L.P. (the “Partnership”) is a Delaware limited partnership in which Atlas Resources, LLC (“Atlas Resources”) of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas America, Inc., a publicly traded company), will be Managing General Partner and Operator, and subscribers to units will be either Limited Partners or Investor General Partners depending upon their individual elections.
The Partnership will be funded to drill development wells which are proposed to be located primarily in the Appalachian Basin located in western Pennsylvania, eastern and southern Ohio, western New York and north central Tennessee.
Subscriptions at a cost of $10,000 per unit, subject to discounts for certain investors, generally will be sold using wholesalers and through broker-dealers including Anthem Securities, Inc., an affiliated company, which will receive on each unit sold to an investor, a 2.5% dealer-manager fee, a 7% sales commission and up to a .5% reimbursement of the selling agents’ bona fide due diligence expenses. Commencement of Partnership operations is subject to the receipt of minimum Partnership subscriptions of $2,000,000 (up to a maximum of $200,000,000) by December 31, 2007.
2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Accounting
The Partnership prepares its financial statements in accordance with accounting principles generally accepted in the United States of America.
Oil and Gas Properties
The Partnership will use 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 will be capitalized. Depreciation and depletion will be computed on a field-by field basis by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows.
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (continued)
September 30, 2006
2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) |
Use of Estimates
The 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 amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.
The Partnership will not be treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit would flow through to the partners as though each partner has incurred such item directly. As a result, each partner must take into account his or her pro-rata share under the partnership agreement of all items of Partnership income and deductions in computing his or her federal income tax liability.
4. | PARTICIPATION IN REVENUES AND COSTS |
The Managing General Partner and the investor partners will participate in revenues and costs in the following manner:
| | Managing
General
Partner | | Investor
Partners | |
| |
| |
| |
Partnership Costs | | | | | |
Organization and offering costs | | 100 | % | 0 | % |
Lease costs | | 100 | % | 0 | % |
Intangible drilling costs (1) | | 0 | % | 100 | % |
Equipment costs | | (2 | ) | (2 | ) |
Operating costs, administrative costs, direct costs, and all other costs | | (3 | ) | (3 | ) |
Partnership Revenues | | | | | |
Interest income | | (4 | ) | (4 | ) |
Equipment proceeds | | (2 | ) | (2 | ) |
All other revenues including production revenues | | (5)(6 | ) | (5)(6 | ) |
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (continued)
September 30, 2006
4. | PARTICIPATION IN REVENUES AND COSTS (continued) |
| (1) | An amount equal to 90% of the subscription proceeds of investor partners in the partnership will be used to pay 100% of the intangible drilling costs incurred by the partnership in drilling and completing its wells. |
| (2) | An amount equal to 10% of the subscription proceeds of investor partners in the partnership will be used to pay a portion of the equipment costs incurred by the partnership in drilling and completing its wells. All equipment costs in excess of that amount will be charged to the Managing General Partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. |
| (3) | These costs will be charged to the parties in the same ratio as the related production revenues are being credited. These costs also include plugging and abandonment costs of the wells after the wells have been drilled and produced. |
| (4) | Interest earned on subscription proceeds before the final closing of the partnership will be credited to investor partners’ accounts and paid not later than the partnerships first cash distribution from operations. After the final closing of the partnership and until the subscription proceeds are invested in the partnership’s natural gas and oil operations any interest income from temporary investments will be allocated pro rata to the investor partners providing the subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited. |
| (5) | The managing general partner and the investor partners in the partnership will share in all of the partnership’s other revenues in the same percentage as their respective capital contributions bear to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner’s total revenue share may not exceed 40% of partnership revenues. |
The partnership will enter into a drilling and operating agreement with Atlas Resources to drill and complete all of the partnership wells for an amount equal to the sum of the following items (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee of $15,000 per well, which will be charged to the investors as part of each well’s intangible drilling costs and the portion of equipment costs paid by the investors; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. This will be proportionately reduced if the partnership’s working interest in a well is less than 100%.
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (continued)
September 30, 2006
4. | PARTICIPATION IN REVENUES AND COSTS (continued) |
| (6) | The actual allocation of partnership revenues between the managing general partner and the investor partners will vary from the allocation described in (5) above if a portion of the managing general partner’s partnership net production revenues is subordinated as described in note 7. |
5. | TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES |
The Partnership intends to enter into the following significant transactions with Atlas Resources and its affiliates as provider under the Partnership agreement:
The partnership will enter into a drilling and operating agreement with Atlas Resources to drill and complete all of the partnership wells for an amount equal to the sum of the following items (i) the cost of permits, supplies, materials, equipment, and all other items used in the drilling and completion of a well provided by third-parties, or if the foregoing items are provided by affiliates of the managing general partner, then those items will be charged at competitive rates; (ii) fees for third-party services; (iii) fees for services provided by the managing general partner’s affiliates, which will be charged at competitive rates; (iv) an administration and oversight fee of $15,000 per well, which will be charged to the investors as part of each well’s intangible drilling costs and the portion of equipment costs paid by the investors; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the managing general partner’s services as general drilling contractor. This will be proportionately reduced if the partnership’s working interest in a well is less than 100%. The cost of the wells will include all ordinary and actual costs of drilling, testing and completing the wells.
Atlas Resources will receive an unaccountable, fixed payment reimbursement for its administrative costs at $75 per well per month, which will be proportionately reduced if the partnership’s working interest in a well is less than 100%.
Atlas Resources will receive well supervision fees for operating and maintaining the wells during producing operations at a competitive rate (currently the competitive rate is $362 per well per month in the primary and secondary drilling areas). The well supervision fees will be proportionately reduced if the partnership’s working interest in a well is less than 100%.
Atlas Resources will charge the partnership a fee for gathering and transportation at a competitive rate (currently 10% of the natural gas price).
Atlas Resources will contribute all the undeveloped leases necessary to cover each of the partnership’s prospects and will receive a credit for its capital account in the partnership equal to the cost of the leases (approximately $11,310 per prospect which will be proportionately reduced if the Partnership’s working interest is the prospect is less than 100%).
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Atlas Resources Public 16-2007 (A) L.P.
(A Delaware Limited Partnership)
NOTES TO FINANCIAL STATEMENT (continued)
September 30, 2006
5. | TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (continued) |
As the Managing General Partner, Atlas Resources will perform all administrative and management functions for the partnership including billing and collecting revenues and paying expenses. Atlas Resources will be reimbursed for all direct costs expended on behalf of the partnership.
Subject to certain conditions, investor partners may present their interests after five years from the partnership’s first cash distribution from operations for purchase by the Managing General Partner. The Managing General Partner is not obligated to purchase more than 5% of the units in any calendar year. In the event that the Managing General Partner is unable to obtain the necessary funds, the Managing General Partner may suspend its purchase obligation.
7. | SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER’S NET PRODUCER REVENUE SHARE |
The Managing General Partner will subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, direct costs, administrative costs, and all other costs not specifically allocated, to the receipt by the investor partners of cash distributions from the Partnership equal to at least 10% per unit, based on $10,000 per unit regardless of the actual price paid, determined on a cumulative basis, in each of the first five 12-month periods beginning with the Partnership’s first cash distribution from operations.
In order to limit the potential liability of the investor general partners for partnership liabilities and obligations, Atlas Resources has agreed to indemnify each investor general partner from any liability incurred which exceeds such partner’s share of undistributed Partnership net assets and insurance proceeds.
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Report of Independent Registered Public Accounting Firm
Board of Directors
ATLAS RESOURCES, LLC.
We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES, LLC. (a Pennsylvania corporation) and subsidiaries (formerly “Atlas Resources, Inc.”) as of September 30, 2005 and 2004, and the related consolidated statements of income, changes in stockholder’s equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company 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 Company’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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ATLAS RESOURCES, LLC. and subsidiaries as of September 30, 2005 and 2004, and the consolidated results of their operations and cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Cleveland, Ohio
January 6, 2006 (except for Note 10, as to which the date is April 7, 2006)
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