Item 1. Business
Cautionary Statement
The Trustee (as defined below), its officers or its agents on behalf of the Trustee may, from time to time, make forward-looking statements (other than statements of historical fact). In addition, this Report on Form 10-K may contain forward-looking statements. When used herein, the words “anticipates,” “expects,” “believes,” “intends” or “projects” and similar expressions are intended to identify forward-looking statements. To the extent that any forward-looking statements are made, the Trustee is unable to predict future changes in gas prices, gas production levels, economic activity, legislation and regulation, and certain changes in expenses of the Trust (as defined below). In addition, the Trust’s future results of operations and other forward-looking statements contained in this Item 1, Item 1A
Item 1A. Risk Factors.
Following is a summary of the principal risks associated with an investment in Units in the Trust.
Natural gas prices fluctuate due to a number of factors, and lower prices will reduce net proceeds to the Trust and distributions to Unitholders.
The Trust’s revenues and distributions to Unitholders are highly dependent on the sales prices as reflected in the Henry Hub Average Price, as defined in the Gas Purchase Contract, and on the quantities of natural gas attributable to the Net Profits Interests. Prices for natural gas can fluctuate widely in response to a number of factors that are beyond the control of Eastern American and the Trust. These factors include:
worldwide economic conditions;
weather conditions;
changes and expectations regarding natural gas production and transportation;
levels of actual and anticipated demand;
price and availability of alternative fuels;
the availability of gathering, transportation and processing facilities; and
the effects of worldwide energy conservation measures.
Low gas prices may reduce production.
Low natural gas prices may reduce the amount of gas that is economic to produce. As a result, the operator could determine during periods of low gas prices to shut in or curtail production. In addition, the operator could determine during periods of low gas prices to plug and abandon marginal wells.
Estimated reserves and future production levels are uncertain.
The value of the Depositary Units depends on, among other things, the proved reserves and production levels attributable to the Net Profits Interests. There are many uncertainties involved in estimating quantities and values of proved reserves and in projecting future rates of production. The reserve data included in this Annual Report are estimates only, and actual quantities and values of natural gas are likely to differ from the estimated amounts. The discounted present values shown for the Net Profits Interests were prepared using guidelines established by the SEC for disclosure of reserves and should not be considered representative of market value.
There are risks inherent in the development and production of natural gas.
Distributions to Unitholders could be adversely affected if any of the risks typically associated with the development, production and transportation of natural gas were to occur, including personal injuries, property damage, well damage and damage to productive formations or equipment.
None of the Trust, the Trustee nor the Unitholders has any control over the operation of the properties.
None of the Trust, Trustee nor the Unitholders is able to influence or control the operation of the properties. All of the wells are operated by Eastern American. As operator, Eastern American has the right to abandon or sell any well if, in its opinion, the well or property ceases to produce or is not capable of producing in commercially paying quantities. In general, upon abandonment of any well to which the Net Profits Interests relate, that portion of the Net Profits Interests will be extinguished.
Gas reserves are depleting assets.
Gas reserves are depleting assets. The reserves attributable to the Net Profits Interests have declined and are expected to continue to decline over time. The accreting value of the Treasury Obligations may not fully offset the depletion of the reserves attributable to the Net Profits Interests.
Compliance with government regulation may be expensive.
The production, transportation and sale of natural gas from the wells to which the Net Profits Interest relate are subject to governmental regulation. Compliance with these regulations may be expensive.
Operating costs, capital expenditures and taxes reduce payments to the Trust.
The operating costs charged in calculating Net Proceeds include a fixed charge, subject to increase of up to 5% annually. In addition, property and production taxes and certain capital expenditures are deducted from gross proceeds in determining the Net Proceeds. In general, increases in chargeable costs will have the effect of reducing the amount of Net Proceeds.
Increased administrative costs reduce distributions to Unitholders.
Administrative costs, including professional services fees and expenses, are deducted prior to distributions to Unitholders. Consequently, increases in administrative costs adversely affect distributions to Unitholders.
External events may result in additional increased administrative costs.
As described elsewhere in this Annual Report on Form 10-K, in November 2005 Ensource Energy Income Fund LP commenced an unsolicited exchange offer in an effort to acquire control of the Trust. The Trust incurred substantially increased administrative costs as a result of the Ensource exchange offer. The costs incurred by the Trust in connection with the Ensource offer decreased distributions to Unitholders. Ensource terminated its unsolicited offer to acquire control of the Trust as of September 15, 2006; however, other similar offers or other types of external events could result in additional increased costs.
The legal status of the Net Profits Interests under some circumstances is unclear.
At the time of the formation of the Trust, Eastern American noted that it was likely that the Net Profits Interests would not be treated as real property interests under the laws of West Virginia and Pennsylvania. Nevertheless, Eastern American recorded the Conveyances in the real property records of West Virginia and Pennsylvania in accordance with local recording acts. Eastern American believes that, if, during the term of the Trust, Eastern American becomes involved as a debtor in a bankruptcy proceeding under the Federal Bankruptcy Code, the Net Profits Interests relating to the Underlying Properties located in West Virginia would be treated as fully conveyed personal property interests. However, if the Conveyances were held to constitute executory contracts, and if such contracts were not to be assumed in a bankruptcy proceeding, the Trust probably would be treated as an unsecured creditor of Eastern American. With respect to the properties located in Pennsylvania, which represented approximately 10% of the reserves attributable to the Net Profits Interests at the inception of the Trust, Eastern American believed that there is a greater risk that the Net Profits Interests would not be treated as fully conveyed property interests and instead the Conveyances could be treated as executory contracts, meaning that the Trust could be treated as an unsecured creditor with respect to those interests.
The Net Profits Interests are subject to any defects in Eastern American’s rights to the Underlying Properties.
The Net Profits Interests are subject to any defects in Eastern American’s rights with respect to the Underlying Properties. Eastern American believes that its interests with respect to the Underlying Properties are good and defensible in accordance with standards generally accepted in the Appalachian oil and gas industry, subject to exceptions which do not detract substantially from the value of its interests. However, it is possible that leases or farmout agreements could be treated as executory contracts if the third party lessor or farmor under a farmout agreement were to become a debtor in bankruptcy, meaning that it is possible that a lease or farmout agreement could be rejected in a bankruptcy proceeding.
The opinion of tax counsel obtained at inception of the Trust is not binding on the IRS or any court.
At the inception of the Trust, Eastern American received an opinion of counsel that the Trust is a grantor trust and not an association taxable as a corporation for Federal income tax purposes, and that each Unitholder would be taxed directly on his pro rata share of the income attributable to assets of the Trust and, subject to certain limitations, would be entitled to claim depletion deductions and tax credits attributable to the Royalty NPI and would be entitled to claim his pro rata share of other deductions attributable to assets of the Trust. However, the opinion of counsel is not binding on the IRS or any court.
Taxable income could exceed cash distributions.
It is possible that taxable income per Depositary Unit may exceed cash distributions per Depositary Unit. In addition, to the extent that distributable cash is used to establish Trust reserves or to repay borrowed funds, Unitholders will recognize taxable income without receiving the cash used to establish reserves or to repay borrowed funds.
Eastern American and the Trust may have conflicts of interest.
The interests of Eastern American and the interests of the Trust and the Unitholders may at times be different. For example, Eastern American’s interests may conflict with those of the Trust and Unitholders in situations involving the development, operation or abandonment of the Underlying Properties or adjacent properties. In making decisions with respect to such operations, or otherwise with respect to the development, operation or abandonment of the Underlying Properties, Eastern American is required to act as a reasonably prudent operator in the Appalachian Basin would act with respect to its own properties, without regard to the existence of the Net Profits Interests and without regard to any possible adverse effect on Eastern Marketing or Eastern American under the Gas Purchase Contract. In addition, Eastern American has agreed not to drill any well within 1,000 feet of any well subject to the Net Profits Interests which produces oil or gas from the same formations or horizons as any such producing well. These covenants would not prohibit Eastern American from drilling additional wells on the same property as the wells subject to the Net Profits Interests provided that Eastern American complies with both of these covenants. In addition, these covenants would not prohibit Eastern American from drilling development wells on adjacent properties provided that Eastern American complies with the 1,000 foot limitation. If Eastern American is permitted under these covenants to drill additional development wells near the wells subject to the Net Profits Interests, the additional wells could cause drainage of the reserves attributable to the Net Profits Interests. These covenants apply only to Eastern American, and do not apply to third parties.
In addition, Eastern American’s interests may conflict with those of the Trust and the Unitholders in situations involving the sale of Underlying Properties. Eastern American has the right to sell all or any portion of the Underlying Properties without restrictions; however, except in limited circumstances where Eastern American may require the Trust to release the Net Profits Interests, the Conveyances provide that the purchaser of any of the Underlying Properties will acquire such Underlying Properties subject to the Net Profits Interests. The Conveyances provide that a purchaser will be subject to the same standards of conduct with respect to development, operation and abandonment of such Underlying Properties as are
applicable to Eastern American. Eastern American has the right, subject to limitations, to cause the Trust to release a portion of the Net Profits Interests in connection with a sale of a portion of the Underlying Properties.
Unitholders have only limited voting rights.
While Unitholders have certain voting rights pursuant to the terms of the Trust Agreement, these rights are more limited than those of stockholders of most corporations. For example, there is no requirement for annual meetings of Unitholders or for an annual or other periodic re-election of the Trustee.
Unitholders could be subject to unlimited liability.
Consistent with Delaware law, the Trust Agreement provides that the Unitholders will have the same limitation on liability as is accorded under the laws of such state to stockholders of a corporation for profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.
There are risks associated with the financial position of Eastern American.
Eastern American is a privately held, independent energy company engaged primarily in the exploration, development, production, transportation and marketing of natural gas within the Appalachian Basin. The ability of Eastern Marketing and Eastern American to perform their obligations under the Gas Purchase Contract depends on their financial condition, which in turn depends upon the supply and demand for natural gas, economic conditions and upon financial, business and other factors, many of which are beyond the control of Eastern American.
None of the Trustee, the Trust nor the Unitholders has any control over the operation of the Underlying Properties.
None of the Trustee, the Trust nor the Unitholders has any influence or control over the operation of the Underlying Properties, all of which are operated by Eastern American.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
Reference is made to Item 1 of this Form 10-K.
Item 3.
Item 3. Legal Proceedings.
None.
Item 4.
Item 4. Submission of Matters to a Vote of Unitholders.
None.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholders Matters and Issuer Purchases of Equity Securities.
The Depositary Units are traded on the New York Stock Exchange under the ticker symbol “NGT.” The high and low prices and distributions paid during the quarters in the two-year period ended December 31, 2006 were as follows:
At March 13, 2007, the 5,900,000 Depositary Units outstanding were held by approximately 221 Unitholders of record.
With respect to the Treasury Obligations, the high and low closing prices per $1,000 face amount for the period from January 1, 2006 to December 31, 2006 were $755.85 and $698.78, respectively. The closing price on December 31, 2006 was $745.06 per $1,000 face amount.
During the fourth quarter of 2006, there were no purchases of Units made by or on behalf of the Trust or any “affiliated purchaser” as defined in Rule 10b-18 (a) (3) under the Exchange Act.
The following graph shows a comparison of cumulative total unitholder return, calculated on a distributions reinvested basis, from December 31, 2001 through December 29, 2006 for the Trust, a peer group index consisting of Hugoton Royalty Trust, LL&E Royalty Trust and Torch Energy Royalty Trust, and a broad New York Stock Exchange market index. The graph assumes that $100 was invested in the Trust's units and the above indices on December 31, 2001. Historic price performance is not necessarily indicative of future price performance.
COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG EASTERN AMERICAN NATURAL GAS TRUST
NYSE MARKET INDEX AND PEER GROUP INDEX
ASSUMES $100 INVESTED ON DEC. 31, 2001
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2006
Item 6.
Item 6. Selected Financial Data.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
General
The Trust does not conduct any operations or activities. The Trust’s purpose is, in general, to hold the Net Profits Interests, to distribute to Unitholders cash which the Trust receives in respect of the Net Profits Interests and to perform certain administrative functions in respect of the Net Profits Interests and the Depositary Units. The Trust derives substantially all of its income and cash flows from the Net Profits Interests.
Under the Gas Purchase Contract, Eastern Marketing purchases gas from the Trust at a variable price for any quarter equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal, for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in The Wall Street Journal, for such contracts which expire during such month and (iii) the closing settlement price per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported in The Wall Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange.
Accordingly, the price payable to the Trust for production may vary based on fluctuations in natural gas futures prices during the relevant calculation period. The price payable to the Trust will have a direct impact, positively or negatively, on the quarterly distributions payable by the Trust to the Unitholders.
During 2004, an oil and gas company contacted Eastern American and inquired as to whether it would sell certain assets situated in Centre County, Pennsylvania including the Horne #1, Horne #2 and Horne #15 wells (the Horne Underlying Properties), which are wells in which the Trust owned a Net Profits Interests. Eastern American reviewed the Trust Agreement and certified to the Trustee that: (i) the gross purchase price to be received by Eastern American for the sale of the Horne Underlying Properties in a single transaction or a series of related transactions was less than $500,000; (ii) the Assignee of the Horne Underlying Properties was not an Affiliate of Eastern American; (iii) the aggregate sale proceeds of $80,205 to be received by the Trust from Eastern American (the Trust’s Horne Sale Proceeds) represented the fair value to the Trust for Net Profits Interests to be released by the Trustee in connection with Eastern American’s sale of the Horne Underlying Properties; and (iv) the Trust’s Horne Sale Proceeds plus the aggregate sale proceeds received by the Trust pursuant to Section 3.02(b)(ii) of the Trust Agreement with respect to all other Net Profits Interests previously released by the Trustee pursuant to Section 3.02(b) during the most recently completed twelve calendar months did not exceed $500,000. Eastern American advised the oil and gas company that it could sell these wells. The Trust’s share of the proceeds of $80,205 was included in the Distributable Income of the Trust during the year ended December 31, 2004.
Also, during 2004, a landowner contacted Eastern American to inquire about the sale of certain wells located on the landowner’s property, including the Wurst #2 well, which is a well in which the Trust owns a Net Profits Interest. Eastern certified to the Trust that (i) the Assignee of the Wurst #2 was not an Affiliate of Eastern, and (ii) the aggregate sale proceeds to be received from all other sales of wells in which the Trust owned a Net Profits Interest and previously released by the Trust during the preceeding twelve (12) calendar months did not exceed $500,000. The Wurst #2 well was found to be uneconomic to operate and was subject to plugging and abandonment by Eastern American if not assigned to the landowner. Eastern American advised the landowner that it could assign this well. The Wurst #2 well had no value and no cash distribution was made to the Trust.
Over the remaining life of the Trust, additional wells may need to be disposed of for similar or other reasons.
The Trust is responsible for paying the Trustee’s fees and all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred by or at the direction of the Trustee. The total of all Trustee fees and Trust administrative expenses for 2006 was $1,317,881 including the Trustee’s fee of $108,000. In addition to such expenses, in 2006, the Trust paid Eastern American an overhead reimbursement of $328,432. The overhead reimbursement increases by 3.5% per year and is payable quarterly.
On December 8, 2004, the Trust announced approval by the Trust Unitholders of a proposal to elect JPMorgan Chase to serve as successor trustee of the Trust upon the effective date of the resignation of The Bank of New York as trustee of and depositary for the Trust and to amend the Trust Agreement to change the compensation of the Trustee. The resignation of The Bank of New York took effect on January 1, 2005. As successor trustee, JPMorgan Chase received annual compensation of $108,000 plus fees and expenses. Effective October 2, 2006, The Bank of New York Trust Company, N.A. acquired the corporate trust business of JPMorgan Chase Bank, N.A. Consequently, The Bank of New York Trust Company, N.A., currently serves as Trustee of the Trust. The Trustee’s annual compensation did not change as a result of the October 2, 2006 acquisition by The Bank of New York Trust Company, N.A. of the corporate trust business of JPMorgan Chase.
During the last two quarters of 2005 and during 2006, the Trust incurred substantially increased fees for professional services relating to the exchange offers made by Ensource Energy Income Fund LP during 2005 and 2006. Expenses relating
to the Ensource exchange offers incurred by the Trust during 2005 totaled approximately $725,798, including $418,639 for fees and expenses the Trust paid to a financial advisory firm in connection with its analysis of the Ensource exchange offers. Expenses relating to the Ensource exchange offers incurred by the Trust during 2006 totaled approximately $701,606, including $387,923 for fees and expenses the Trust paid to a financial advisory firm in connection with its analysis of the Ensource exchange offers.
The costs the Trust incurs in the future will fluctuate depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services.
Critical Accounting Policies
The following is a summary of the critical accounting policies followed by the Trust.
Basis of Accounting:
The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America due to the following: (i) certain cash reserves may be established for contingencies which were not accrued in the financial statements; (ii) amortization of the Net Profits Interests in gas properties is charged directly to Trust Corpus; and (iii) the sale of the Net Profits Interests is reflected in the Statements of Distributable Income as cash proceeds to the Trust.
Net Profits Interests in Gas Properties:
The Net Profits Interests in gas properties are periodically assessed to determine whether their net capitalized cost is impaired. The Trust will determine if a writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the discounted future net revenues attributable to proved gas reserves of the Underlying Properties. Any such writedown would not reduce distributable income, although it would reduce Trust Corpus.
Amortization of the Net Profits Interests in gas properties is calculated on a units-of-production basis, whereby the Trust’s cost basis in the properties is divided by total Trust proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce distributable income, rather it is charged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
The Net Profits Interest impairment test and the determination of amortization rates are dependent on estimates of proved gas reserves attributable to the Trust. Numerous uncertainties are inherent in estimating reserve volumes and values, including economic and operating conditions, and such estimates are subject to change as additional information becomes available.
Income Taxes:
Tax counsel to the Trust advised the Trust at the time of formation that, under then current tax laws, the Trust would be classified as a grantor trust for federal and state income tax purposes and, therefore, would not be subject to taxation at the Trust level. The Trust continues to be tax exempt. Accordingly, no provision for federal or state income taxes has been made. However, the opinion of tax counsel is not binding on taxing authorities.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans (“SFAS 158”), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. This Statement is effective for financial statements issued for fiscal years ending after December 15, 2006. The Trust does not have Defined Benefit Pension or Other Postretirement Plans. Therefore, SFAS 158 does not apply to the Trust and had no impact on the financial statements.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109 (“FIN 48”). FIN 48 prescribes a model for how a company should recognize, measure, present, and disclose in its financial statements uncertain tab positions that it has taken or expects to take on a tax return. For deferral income tax purposes, the Trust has been treated and expects to continue to be treated not as an association taxable as a corporation, but as a grantor trust that is not subject to Federal income tax as an entity separate from its beneficial owners. Therefore, FIN 48 does not apply to the Trust and would have no impact on the financial statements.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than the distributions received from the Net Profits Interests.
In accordance with the provisions of the Conveyances, generally all revenues received by the Trust, net of Trust administrative expenses and the amount of established reserves, are distributed currently to the Unitholders.
The Trust did not have any contractual obligations as of December 31, 2006. At December 31, 2006, the Trust had General and Administrative Expenses Payable of $223,442 and Distributions Payable of $2,681,087.
Results of Operations
2006 Compared with 2005 The Trust’s Distributable Income was $14,158,872 for the year ended December 31, 2006 as compared to $14,597,387 for the year ended December 31, 2005. This decrease was due to a decrease in Royalty Income for the year ended December 31, 2006 ($17,663,792) as compared to the year ended December 31, 2005 ($18,179,459). The decrease in Royalty Income was due to a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2006 (1,847 Mmcf) as compared to the year ended December 31, 2005 (1,956 Mmcf). This decrease was offset by an increase in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($9.538 per Mcf for the year ended December 31, 2006; $9.315 per Mcf for the year ended December 31, 2005). The decline in production is primarily attributable to natural production declines. Taxes on Production and Property were $1,297,539 for the year ended December 31, 2006 as compared to $1,256,330 for the year ended December 31, 2005. The increase in taxes is due to a new West Virginia tax on the Severance of Natural Resources that is effective for gas produced after November 30, 2005. The additional Severance Tax rate is four and seven-tenths cents per MCF. Trust General and Administrative Expenses were $1,646,313 for the year ended December 31, 2006 as compared to $1,791,894 for the year ended December 31, 2005. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees incurred as a direct result of the exchange offers made by Ensource Energy Income Fund LP, which were terminated on September 15, 2006.
During the year ended December 31, 2006, the Trustee released $500,000 from the Cash Reserve balance compared to the addition of $885,000 to the cash reserve for the year ended December 31, 2005. This Reserve was established to facilitate the payment of vendor invoices on a timely basis. The change of this Reserve increased the Distribution Amount by $500,000 or $0.085 per unit for the year ended December 31, 2006 and decreased the Distribution Amount by $885,000 or $0.15 per unit for the year ended December 31, 2005. Amortization of Net Profits Interests in Gas Properties was $2,942,047 for the year ended December 31, 2006 as compared to $3,321,243 for the year ended December 31, 2005. This decrease was due to the decrease in production volumes and a decrease in the depletion rate to $1.5932 for the year ended December 31, 2006 from $1.6976 for the year ended December 31, 2005, due to higher reserves.
The average price payable to the Trust for gas production attributable to the Net Profits Interests was $9.538 per Mcf for the year ended December 31, 2006 and $9.315 per Mcf for the year ended December 31, 2005. The price per Mcf was higher for the year ended December 31, 2006 than for the corresponding year ended December 31, 2005 due to an increase in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($8.371 per Dth for the year ended December 31, 2006; $8.168 per Dth for the year ended December 31, 2005).
2005 Compared with 2004 The Trust’s Distributable Income was $14,597,387 for the year ended December 31, 2005 as compared to $12,019,847 for the year ended December 31, 2004. This increase was due to an increase in Royalty Income for the year ended December 31, 2005 ($18,179,459) as compared to the year ended December 31, 2004 ($14,449,208). The increase in Royalty Income was due to an increase in the average price payable to the Trust under the Gas Purchase Contract as discussed below ($9.315 per Mcf for the year ended December 31, 2005; $6.989 per Mcf for the year ended December 31, 2004). This increase was offset by a decrease in production of gas attributable to the Net Profits Interests for the year ended December 31, 2005 (1,956 Mmcf) as compared to the year ended December 31, 2004 (2,068 Mmcf). The decline in production is primarily attributable to natural production declines and the sale of wells. Taxes on Production and Property were $1,256,330 for the year ended December 31, 2005 as compared to $989,430 for the year ended December 31, 2004. The increase in taxes is due directly to the increase in Royalty Income as discussed above. The production tax for the quarter also includes one month of charges related to a new West Virginia tax on the Severance of Natural Resources that is effective for gas produced after November 30, 2005. The additional Severance Tax rate is four and seven-tenths cents per MCF. Trust General and Administrative Expenses were $1,791,894 for the year ended December 31, 2005 as compared to $1,002,397 for
the year ended December 31, 2004. The increase of $789,497 in General and Administrative Expenses was due primarily to professional fees of approximately $725,798 incurred as a direct result of the Ensource exchange offer described above. The Distributable Income includes no Cash Proceeds on Sale of Net Profits Interests for the year ended December 31, 2005, while $80,205 was recognized in the corresponding prior year.
During the year ended December 31, 2005, the Trustee added an additional $885,000 to the Cash Reserve balance compared to the year ended December 31, 2004 in the amount of $100,000. This Reserve was established to facilitate the payment of vendor invoices on a timely basis. The increase of this Reserve reduced the Distribution Amount by $885,000 or $0.15 per unit for the year ended December 31, 2005 and by $100,000 or $0.0169 per unit for the year ended December 31, 2004. Amortization of Net Profits Interests in Gas Properties was $3,321,243 for the year ended December 31, 2005 as compared to $3,818,158 for the year ended December 31, 2004. This decrease was due to the decrease in production volumes and a decrease in the depletion rate to $1.6976 for the year ended December 31, 2005 from $1.8465 for the year ended December 31, 2004, due to higher reserves.
The average price payable to the Trust for gas production attributable to the Net Profits Interests was $9.315 per Mcf for the year ended December 31, 2005 and $6.989 per Mcf for the year ended December 31, 2004. The price per Mcf was higher for the year ended December 31, 2005 than for the corresponding year ended December 31, 2004 due to an increase in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($8.168 per Dth for the year ended December 31, 2005; $6.054 per Dth for the year ended December 31, 2004).
Off-Balance Sheet Arrangements
The Trust does not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Trust’s financial condition, changes in financial condition, revenue or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Trust does not engage in any operations and does not utilize market risk sensitive instruments, either for trading purposes or for other than trading purposes. As described in detail elsewhere herein, the Depositary Units consist of beneficial ownership of one unit of beneficial interest in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon Treasury Obligation maturing on May 15, 2013. High and low price information for the Treasury Obligations is included under Item 5. As described in detail elsewhere herein, gas production attributable to the Net Profits Interest is sold to a wholly owned subsidiary of Eastern American pursuant to the Gas Purchase Contract described herein.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Financial Statements
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus as of December 31, 2006 and 2005
Statements of Distributable Income for the years ended December 31, 2006, 2005 and 2004
Statements of Changes in Trust Corpus for the years ended December 31, 2006, 2005 and 2004
Notes to Financial Statements
Supplemental Information
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by several parties, including without limitation, the working interest owner, Eastern American Energy Corporation (“Eastern American”), and the independent reserve engineer to The Bank of New York Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure. In addition, the Trustee is required by the Trust Agreement to engage and has engaged an independent registered public accounting firm to review the quarterly
financial statements of the Trust and audit the annual financial statements of the Trust, which includes financial data provided by Eastern American.
As of December 31, 2006, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures are effective.
Due to the contractual arrangements of (i) the Trust Agreement and (ii) the rights of the Trustee under the Conveyances regarding information furnished by Eastern American, there are certain potential weaknesses that may limit the effectiveness of disclosure controls and procedures established by the Trustee or its employees and their ability to verify the accuracy of certain financial information. The contractual limitations creating potential weaknesses in disclosure controls and procedures may be deemed to include:
·Eastern American and its consolidated subsidiaries manage information relating to the Trust, including (i) historical operating data, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, the effects of regulatory changes and the number of producing wells and acreage, (ii) plans for future operating and capital expenditures and (iii) geological data relating to reserves; and
·The Trustee necessarily relies upon the independent reserve engineer, as an expert with respect to the annual reserve report, which includes projected production, operating expenses and capital expenses.
Other than reviewing the financial and other information provided to the Trust by Eastern American and the independent reserve engineer, the Trustee made no independent or direct verification of this financial or other information.
The Trustee does not intend to expand its responsibilities beyond those permitted or required by the Trust Agreement and those required under applicable law.
The Trustee does not expect that the Trustee’s disclosure controls and procedures or the Trustee’s internal control over financial reporting will prevent all errors and all fraud. Further, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected.
Changes in Internal Control Over Financial Reporting
In connection with the evaluation by the Trustee of changes in internal control over financial reporting of the Trust that occurred during the Trust’s last fiscal quarter, no change in the Trust’s internal control over financial reporting was identified that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.
Trustee’s Report on Internal Control over Financial Reporting
The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2006. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
A registrant’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The Trust has no directors or executive officers. The Trustee is a corporate trustee which may be removed by the affirmative vote of holders of a majority of the Trust Units then outstanding at a meeting of the Unitholders of the Trust at which a quorum is present. The Trust is not required to and does not hold annual meetings of the Unitholders.
The Trust also does not have an audit committee or body serving a similar function. The Trust has not adopted a code of ethics, as the Trust has no directors, officers, or employees. The Trust has not adopted a process by which Unitholders may communicate with board members, as the Trust has no board members or persons fulfilling a similar function. Unitholders may contact the Trustee at the following address: The Bank of New York Trust Company, N.A., Trustee of Eastern American Natural Gas Trust, Global Corporate Trust, 919 Congress Avenue Suite 500, Austin, Texas 78701.
Item 11.
Item 11. Executive Compensation.
The Trust has no officers or directors, and is administered by the Trustee. For the year ended December 31, 2006, The Bank of New York Trust Company, N.A., as Trustee, received $108,000, for the year ended December 31, 2005, JPMorgan Chase Bank, N.A. received $108,000 and for the year ended December 2004, The Bank of New York, as Trustee, received $45,000 annually, as Trustee fees and $1,209,881, $1,366,570 and $650,805, respectively, as reimbursement of legal, accounting, and other professional expenses for such services. Effective January 1, 2005, the annual Trustee fee was fixed at $108,000.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
(a) Security Ownership of Certain Beneficial Owners.
Based on filings with the Securities and Exchange Commission, the Trust is not aware of any person owning beneficially more than 5% of the Units as of March 1, 2007.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The Trust knows of no arrangements, including the pledge of securities of the Trust, the operation of which may at a subsequent date result in a change in control of the Trust.
(d) Securities authorized for issuance under equity compensation plans.
The Trust has no equity compensation plans.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The Trust has no directors.
Item 14.
Item 14. Principal Accounting Fees and Services.
Audit Fees
The fees PricewaterhouseCoopers LLP billed the Trust for each of the last two fiscal years for professional services rendered in connection with the audits of the Trust’s annual financial statements and review of the Trust quarterly interim financial statements were $193,516 in 2006 and $185,250 in 2005.
Audit-Related Fees
PricewaterhouseCoopers LLP did not bill the Trust any additional fees in the last two fiscal years for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements.
Tax Fees
The fees, including expenses, PricewaterhouseCoopers LLP billed the Trust for each of the last two fiscal years for compliance, tax advice, or planning were $128,000 in 2006 and $123,715 in 2005.
All Other Fees
PricewaterhouseCoopers LLP did not bill the Trust any additional fees in the last two fiscal years for products and services provided by PricewaterhouseCoopers LLP, other than services reported above.
Pre-Approval Policies
The Trust does not have an audit committee or body performing a similar function. Pre-approval of all services performed by PricewaterhouseCoopers LLP and approval of the related fees is granted by the Trustee.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
Schedules
All schedules have been omitted because they are not required, not applicable or the information required has been included elsewhere herein.
Exhibits
Except as otherwise indicated below, all exhibits, except Exhibit 31 and Exhibit 32, are incorporated herein by reference to the indicated exhibits to filings previously made by the registrant with the Securities and Exchange Commission. All references are to the registrant’s Registration Statement on Form S-1, Registration No. 33-56336, except for Exhibit 3.1, which is incorporated by reference to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1994.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on this 16th day of March, 2007.
The Registrant, Eastern American Natural Gas Trust, has no principal executive officer, principal financial officer, controller or principal accounting officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided.
[Ryder Scott Company, Independent Petroleum Engineers Letterhead]
January 29, 2007
Eastern American Natural Gas Trust
The Bank of New York Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
Gentlemen:
Pursuant to your request, we present below estimates of the net proved reserves attributable to the interests of the Eastern American Natural Gas Trust (Trust) as of December 31, 2006. The Trust is a grantor trust formed to hold interests in certain domestic oil and gas properties owned by Eastern American Energy Corporation (EAEC), a wholly owned subsidiary of Energy Corporation of America (ECA). The interests conveyed to the Trust consist of a net profits interest derived from working and royalty interests in numerous properties. The Net Profits Interest consists of (1) a life-of-properties interest (“Royalty NPI”) and (2) a term interest (“Term NPI”). The properties included in the Trust are located in the states of Pennsylvania and West Virginia.
The estimated reserve quantities and future income quantities presented in this report are related to a large extent to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2006 were used in the preparation of this report as required by Securities and Exchange Commission (SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however, actual future prices may vary significantly from December 31, 2006 prices for reasons discussed in more detail in other sections of this report. Therefore, quantities of reserves actually recovered and quantities of income actually received may differ significantly from the estimated quantities presented in this report.
Reserve quantities are calculated differently for a Net Profits Interest because such interests do not entitle the Trust to a specific quantity of oil or gas but to 90 percent of the Net Proceeds derived therefrom beginning on January 1, 2007 for natural gas. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves attributable to the Net Profits Interest between the interest held by the Trust and the interests to be retained by EAEC. For purposes of this presentation, the proved reserves attributable to the Net Profits Interests have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests. Accordingly, the reserves presented for the Net Profits Interest reflect quantities of gas that are free of future costs or expenses based on the price and cost assumptions utilized in this report. The allocation of proved reserves of the Net Profits Interest between the Trust and EAEC will vary in the future as relative estimates of future gross revenues and future net incomes vary. Furthermore, EAEC requested that for purposes of our report the “Royalty NPI” be calculated beyond the Liquidation Date of May 15, 2013, even though by the terms of the Trust Agreement the Royalty NPI will be sold by the Trustee on or about this date and a liquidating distribution of the sales proceeds from such sale would be made to holders of Trust Units. The Trust Agreement provides that the “Term NPI” entitles the Trust to receive the net proceeds from the gas produced from the properties burdened by the “Term NPI” until the earlier of May 15, 2013 or until such time as 41,683 MMCF of gas has been produced. For purposes of this report, the “Term NPI” was limited to May 15, 2013.
All gas volumes are sales gas expressed in MMCF at the pressure and temperature bases of the area where the gas reserves are located. The estimated future net cash inflows are described later in this report.
The proved reserves presented in this report comply with the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission Staff Accounting Bulletins, and are based on the following definitions and criteria:
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Proved reserves of crude oil, natural gas, or natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by actual production or formation tests. In certain instances, proved reserves may be assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by fluid contacts, if any, and (2) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data becomes available. Proved natural gas reserves consist of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of natural gas liquids, for lease and plant fuel, and for the exclusion of non-hydrocarbon gases if they occur in significant quantities.
Reserves that can be produced economically through the application of improved recovery techniques are included in the proved classification when these qualifications are met: (1) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (2) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including (1) pressure maintenance, (2) cycling, and (3) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or natural gas liquids being held in underground or surface storage.
(i) “developed reserves” which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) “developed producing reserves” which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) “developed non-producing reserves” which are those proved developed reserves which exist behind the casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of a new well; and
(ii) “undeveloped reserves” which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.
In accordance with the requirements of FASB 69, estimates of future cash inflows, future costs and future net cash inflows before income tax, as well as estimated reserve quantities, as of December 31, 2006 from this report are presented in the following table:
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For Net Profits Interest, the future cash inflows are, as described previously, after consideration of future costs or expenses based on the price and cost assumptions utilized in this report. Therefore, the future cash inflows are the same as the future net cash inflows. The effects of depreciation, depletion and federal income taxes have not been taken into account in estimating future net cash inflows.
EAEC furnished us gas prices in effect at December 31, 2006 and with its forecasts of future gas prices which take into account Securities and Exchange Commission guidelines, current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with Securities and Exchange Commission guidelines, the future gas prices used in this report make no allowances for future gas price increases or decreases which may occur as a result of inflation nor do they account for seasonal variations in gas prices which are likely to cause future yearly average gas prices to be somewhat higher than December gas prices. In those cases where contract market-out has occurred, the current market price was held constant to depletion of the reserves. In those cases where market-out has not occurred, contract gas prices including fixed and determinable escalations, exclusive of inflation adjustments, were used until the contract expired and then reduced to the current market price for similar gas in the area and held at this reduced price to depletion of the reserves.
This report utilized the terms of the gas contract between Eastern Marketing Corporation (a wholly owned subsidiary of EAEC) and the Trust. Gas price is to be determined by a weighted price consisting of two components during a primary term defined to begin on January 1, 1993 and end December 31, 1999. The first component is the “Fixed” price which has been defined as $2.66 per Mcf beginning January 1, 1993. This price escalates 5 percent per year on January 1 of each year during the primary term beginning in 1994. The second component is the “Variable” price which for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu, plus $0.30 per MMBtu, multiplied by 110 percent to effect a Btu adjustment. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter as the average price of the three months in such quarter where each month’s price is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in the Wall Street Journal, for such contracts which expired in each of the five months prior to each month of such quarter, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in the Wall Street Journal, for such contracts which expire during such month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts for such month, as reported in the Wall Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange. The weighted average price is determined by giving the “Fixed” price a 66 2/3 percent weighting and the variable price a 33 1/3 percent weighting.
Since the primary term is complete, the purchase price under the gas contract will be equal to the “Variable” price. EAEC computed the “Variable” price under the gas contract as of December 31, 2006 as $8.096 per Mcf, utilizing $7.060 as the Henry Hub Average Spot Price computed in accordance with the gas contract.
Operating costs for the leases and wells in this report were supplied by EAEC and include only costs defined as applicable under terms of the Trust. The current operating costs were held constant throughout the life of the properties. This study does not consider the salvage value of the lease equipment or the abandonment cost.
No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. No attempt has been made to quantify or otherwise account for any accumulated gas production imbalances that may exist.
Our reserve estimates are based upon a study of the properties in which the Trust has interests; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental
A-3
liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, in any, caused by past operating practices. EAEC informed us that it has furnished us all of the accounts, records, geological and engineering data and reports and other data as were required for our investigation. The ownership interests, terms of the Trust, prices, taxes, and other factual data furnished to us in connection with our investigation were accepted as represented. The estimates presented in this report are based on data available through September, 2006.
At the time of formation of the Trust, EAEC assigned The Trust an interest in 65 undeveloped locations. During the period 1993 through 1998, EAEC has completed it’s drilling obligation. A total of 59 wells were drilled over this period. Two wells were not drilled due to title failure and four wells were not drilled due to short spacing. Reserves and projections of future production are included for the four locations which were not drilled due to short spacing.
The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered. Moreover, estimates of proved reserves may increase or decrease as a result of future operations of EAEC. Moreover, due to the nature of the Net Profits Interest, a change in the future costs, or prices different from those projected herein may result in a change in the computed reserves and the Net Proceeds to the Trust even if there are no revisions or additions to the gross reserves attributed to the property.
The future production rates from properties now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Properties which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.
The future prices received by EAEC for the sale of its production may be higher or lower than the prices used in this report as described above, and the operating costs and other costs relating to such production may also increase or decrease from existing levels; however, such possible changes in prices and costs were, in accordance with rules adopted by the Securities and Exchange Commission, omitted from consideration in preparing this report.
At the request of EAEC, we have included the following table which summarizes the total net reserves estimates from combined interest of EAEC and the Trust in the Underlying Properties:
Estimated Net Reserve Data
Certain Combined Leasehold Interests of
Eastern America Energy Corporation
And The Trust
As of December 31, 2006
SEC Parameters
The estimated future net income associated with the foregoing volumes and the 10 percent discounted estimated future net income was $215,728,419 and $88,414,492, respectively. This evaluation utilizes the same price and cost assumptions that were utilized for evaluating the Trust and discussed earlier in the letter. The properties which are included in the “Term NPI” were allowed to run for their full economic life in this evaluation.
Neither Ryder Scott Company nor any of its employees has any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future cash inflows for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Larry T. Nelms P. E.
Managing Senior Vice President
LTN:ph
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EASTERN AMERICAN NATURAL GAS TRUST
FINANCIAL STATEMENTS
as of December 31, 2006 and 2005
and for the years ended
December 31, 2006, 2005 and 2004
Report of Independent Registered Public Accounting Firm
To the Unit Holders of Eastern American Natural Gas Trust and The Bank of New York Trust Company, N.A., Trustee:
We have completed integrated audits of Eastern American Natural Gas Trust’s financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Financial statements
We have audited the accompanying statements of assets, liabilities and trust corpus of Eastern American Natural Gas Trust (the “Trust”) as of December 31, 2006 and 2005, and the related statements of distributable income, and statements of changes in trust corpus for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Trustee. 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. An audit 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 the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2, these financial statements were prepared on the basis of accounting prescribed by the Trust Agreement, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Trust at December 31, 2006 and 2005, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006, on the basis of accounting described in Note 2.
Internal control over financial reporting
Also, in our opinion, the Trustee’s assessment, included in the Trustee’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Trust maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on the Trustee’s assessment and on the effectiveness of the Trust’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A trust’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
March 16, 2007
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
as of December 31, 2006 and 2005
The accompanying notes are an integral part of these financial statements.
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF DISTRIBUTABLE INCOME
for the years ended
December 31, 2006, 2005 and 2004
The accompanying notes are an integral part of these financial statements.
EASTERN AMERICAN NATURAL GAS TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
for the years ended
December 31, 2006, 2005 and 2004
The accompanying notes are an integral part of these financial statements.
EASTERN AMERICAN NATURAL GAS TRUST
NOTES TO FINANCIAL STATEMENTS
1. Organization of the Trust:
The Eastern American Natural Gas Trust (the “Trust”) was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) among Eastern American Energy Corporation (“Eastern American”), as grantor, Bank of Montreal Trust Company, as Trustee, and Wilmington Trust Company, as Delaware Trustee (the “Delaware Trustee”). Effective May 8, 2000, The Bank of New York acquired the corporate trust business of the Bank of Montreal Trust Company / Harris Trust, and consequently, The Bank of New York served as trustee of the Trust. On November 20, 2004, the holders of a majority of the Trust Units voting at a special meeting approved the resignation of The Bank of New York as trustee and depository of the Trust and the appointment of JPMorgan Chase Bank, N.A. as successor trustee of the Trust, effective as of January 1, 2005. Effective October 2, 2006, The Bank of New York Trust Company, N. A. replaced JPMorgan Chase Bank, N.A. as trustee in connection with the sale by JPMorgan Chase Bank of substantially all of its corporate trust business to The Bank of New York. Consequently, references herein to the “Trustee” mean Bank of Montreal Trust Company until May 8, 2000; The Bank of New York as successor Trustee from May 8, 2000 through December 31, 2004; JPMorgan Chase Bank, N.A. as successor trustee, from January 1, 2005 through October 2, 2006; and The Bank of New York, N.A. as successor trustee, effective as of October 2, 2006. The transfer agent for the Trust is Bondholder Communications, an affiliate of The Bank of New York Trust Company, N.A.
The purpose of the Trust is to acquire and hold net profits interests owned by Eastern American in 650 producing gas wells and 65 proved development well locations in West Virginia and Pennsylvania (the “Underlying Properties”). The Underlying Properties are operated by Eastern American. The Net Profits Interests (the “Net Profits Interests”) consist of a Royalty interest in 322 wells and a Term interest in the remaining wells and locations. Eastern American drilled 59 of the 65 development wells.
The Royalty NPI is not limited in term or amount. Under the Trust Agreement, the Trustee is directed to sell all remaining Royalty NPI after May 15, 2012 and prior to May 15, 2013, and net proceeds from selling such Royalty NPI will be distributed to Unitholders on the first quarterly payment date following the receipt of such proceeds by the Trust. The Term NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMcf of gas has been produced which is attributable to Eastern American’s net revenue interests in the properties burdened by the Term NPI. As of December 31, 2006, 23,661 MMcf of such gas had been produced.
Eastern American can sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trustee or the Unitholders. In limited circumstances, Eastern American also can transfer the Underlying Properties and require the Trust to release the NPI burdening that property, without the consent of the Trustee or Unitholders, subject to payment to the Trust of the fair value of the interest released. In addition, any abandonment of a well included in the Underlying Properties or the Development Wells will extinguish that portion of the Net Profits Interests that relate to such well.
Four (4) of the remaining six (6) development wells were closely offset by third parties. Since the wells drilled by the third parties were within 1,000 feet of these development wells, Eastern American had a disagreement with the Trust over Eastern American’s obligation to drill these closely offset development wells. The Trust agreed that, in lieu of drilling these closely offset development wells Eastern American can provide the Trust, on an annual basis commencing on April 1, 1997, and over the remaining life of the Trust, a volume of gas which is equal to the projected volumes of the wells as if they had been drilled. These volumes have been estimated by the Ryder Scott Company.
The two (2) remaining development wells were not drilled because Eastern American was unable to cure various title defects associated with these wells. Eastern American advised the Trust that it made a diligent effort to cure title but was unsuccessful. In West Virginia, an oil and gas well cannot be drilled unless a full and complete 100% leasehold interest is first obtained. Drilling an oil and gas well without obtaining the entire leasehold estate would expose the oil and gas operator and the Trust to a possible suit for trespass. Pursuant to the Term Net Profits Interest Conveyance, if the state of title to the drill site to any development well renders such property undrillable in the good faith opinion of Eastern American under the Reasonably Prudent Operator Standard then such drill site(s) shall be construed as a development well(s). Consequently, Eastern American has fulfilled its commitment to the Trust to drill the required number of development wells.
On March 15, 1993, 5,900,000 depositary units were issued in a public offering at an initial public offering price of $20.50 per depositary unit. Each depositary unit consists of beneficial ownership of one unit of beneficial interest (“Trust Unit”) in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury Obligation (“Treasury Obligation”) maturing on May 15, 2013. Of the net proceeds from such offering, $27,787,820 was used to purchase $118,000,000 in face amount of Treasury Obligations and $93,162,180 was paid to Eastern American in
EASTERN AMERICAN NATURAL GAS TRUST
NOTES TO FINANCIAL STATEMENTS
consideration for the conveyance of the Net Profits Interests to the Trust. The Trust acquired the Net Profits Interests effective as of January 1, 1993. The Treasury Obligations are directly owned by the Unitholders and are not part of the Trust Corpus. The Treasury Obligations are on deposit with the Trustee pursuant to the Deposit Agreement.
The Net Profits Interests are passive in nature, and neither the Trustee nor the Delaware Trustee has management control or authority over, nor any responsibility relating to, the operation of the properties subject to the Net Profits Interests. The Trust Agreement provides, among other things, that the Trust shall not engage in any business or commercial activity or acquire any asset other than the Net Profits Interests initially conveyed to the Trust; the Trustee may establish a reserve for payment of any liability which is contingent, uncertain in amount or that is not currently due and payable; the Trustee is authorized to borrow funds required to pay liabilities of the Trust, provided that such borrowings are repaid in full prior to further distributions to Unitholders; and the Trustee will make quarterly cash distributions to Unitholders from funds of the Trust.
2. Significant Accounting Policies:
The following is a summary of the significant accounting policies followed by the Trust.
Basis of Accounting:
The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America due to the following: i) certain cash reserves may be established for contingencies which were not accrued in the financial statements; ii) amortization of the Net Profits Interests in gas properties is charged directly to Trust Corpus; and iii) the sale of the Net Profits Interests is reflected in the Statements of Distributable Income as cash proceeds to the Trust.
Cash:
Cash consists of highly liquid instruments with maturities at the time of acquisition of three months or less.
Net Profits Interests in Gas Properties:
The Net Profits Interests in gas properties are periodically assessed to determine whether their net capitalized cost is impaired. The Trust will determine if a writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the discounted future net revenues attributable to proved gas reserves of the Underlying Properties. Any such writedown would not reduce Distributable Income, although it would reduce Trust Corpus.
Significant dispositions or abandonment of the Underlying Properties are charged to Net Profits Interests and the Trust Corpus.
Amortization of the Net Profits Interests in gas properties is calculated on a units-of-production basis, whereby the Trust’s cost basis in the properties is divided by total Trust proved reserves to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable Income, rather it is charged directly to Trust Corpus. Revisions to estimated future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
The conveyance of the Royalty and Term Interests to the Trust was accounted for as a purchase transaction. The $93,162,180 reflected in the Statements of Assets, Liabilities and Trust Corpus as Net Profits Interests in Gas Properties represents 5,900,000 Trust Units valued at $20.50 per depository unit less the $27,787,820 paid for Treasury obligations. The carrying value of the Trust’s investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.
Revenues and Expenses:
The Trust serves as a pass-through entity, with items of depletion, interest income and expense, and income tax attributes being based upon the status and election of the Unitholders. Thus, the Statements of Distributable Income purport to show Distributable Income, defined as Trust income available for distribution to Unitholders before application of those Unitholders’ additional expenses, if any, for depletion, interest income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue, with royalty income recorded as reserves are extracted from the Underlying Properties and sold. Expenses are also recognized on an accrual basis. Operating expenses which include Taxes on Property and Production and Operating Cost Charges are recognized as incurred pursuant to the Conveyances on a per well production basis. The payment provisions of the Gas Purchase Contract between the Trust and Eastern Marketing Corporation (“Eastern Marketing”), a wholly owned subsidiary of Eastern American, require payment with respect to gas production for a calendar
EASTERN AMERICAN NATURAL GAS TRUST
NOTES TO FINANCIAL STATEMENTS
quarter to be made to the Trust on or before the tenth day of the third month following such quarter.
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Segment Information:
In 1998, the Trust adopted Statement of Financial Accounting Standards No. 131, “Disclosure about Segments of an Enterprise and Related Information.” The Trust’s sole activity is earning royalty income from gas properties and, consequently, the Trust has only one operating segment, net profits interests in gas properties. Substantially all of the Trust’s net profits interests are located in the Appalachian region.
3. Income Taxes:
Tax counsel to Eastern American advised Eastern American at the time of formation that, under then current tax laws, the Trust would be classified as a grantor trust for federal and state income tax purposes and, therefore, would not be subject to taxation at the Trust level. The Trust continues to be tax exempt. Accordingly, no provision for federal or state income taxes has been made. However, the opinion of tax counsel is not binding on taxing authorities.
The Unitholders are considered, for income tax purposes, to own the Trust’s income and principal as though no trust were in existence. Thus, the taxable year for reporting a Unitholder’s share of the Trust income, expense and credits are controlled by the Unitholder’s taxable year and method of accounting, not the taxable year and method of accounting employed by the Trust.
4. Distributions to Unitholders:
The Trustee determines for each quarter the amount available for distribution to the Unitholders. Such amount will be equal to the excess, if any, of the cash received by the Trust, on or before the tenth day of the third month following the end of each calendar quarter ending prior to the dissolution of the Trust, from the Net Profits Interests then held by the Trust attributable to production during such quarter, plus, with certain exceptions, any other cash receipts of the Trust during such quarter, over the liabilities of the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established at the discretion of the Trustee for the payment of contingent or future obligations of the Trust. Cash received by the Trustee in a particular quarter from the Net Profits Interests will reflect actual gas production for a portion of such quarter and a production estimate for the remainder of such quarter, such estimate to be adjusted to actual production in the following quarter. In accordance with the Trust Agreement and Delaware law, Unitholders should be shielded from direct liability for any environmental liabilities. However, costs and expenses incurred by Eastern American for certain Capital Costs associated with environmental liabilities arising after the effective date of the Conveyances would reduce Net Proceeds, and would therefore be borne, in part, by the Unitholders.
Net Proceeds Receivable included in the Statements of Assets, Liabilities and Trust Corpus as of December 31, 2006 are expected to be received by the Trust and distributed to the Unitholders on March 15, 2007. The December 31, 2005 Net Proceeds Receivable were received and distributed by the Trust on March 15, 2006.
5. Related Party Transactions:
The Trust is responsible for paying all legal, accounting, engineering and stock exchange fees, printing costs and other administrative expenses incurred at the direction of the Trustee. The total of all Trustee fees and Trust administrative expenses was $1,317,881 for the year ended December 31, 2006, $1,474,570 for the year ended December 31, 2005, and $695,805 for the year ended December 31, 2004. In accordance with the Trust Agreement, the Trustee pays Eastern American an annual fee which increases by 3.5% per year, payable quarterly, to reimburse Eastern American for overhead expenses. The initial fee at the inception of the Trust was $210,000. The Trustee paid Eastern American $328,432, $317,324 and $306,592 for overhead expenses for 2006, 2005 and 2004 respectively. Operating Cost Charges included in the Statements of Distributable Income are paid to Eastern American.
Gas production attributable to the Net Profits Interests is purchased from the Trust by Eastern Marketing pursuant to a Gas Purchase Contract, which effectively commenced as of January 1, 1993 and expires upon the termination of the Trust.
Pursuant to the Gas Purchase Contract, Eastern Marketing is obligated to purchase such gas production at a purchase price per Mcf equal to the greater of the Index Price, as defined below, or a Floor Price, for gas produced in any quarter during the
EASTERN AMERICAN NATURAL GAS TRUST
NOTES TO FINANCIAL STATEMENTS
Primary Term, which ended December 31, 1999. Effective January 1, 2000, Eastern Marketing is obligated to purchase such gas production at a purchase price per Mcf equal to the Index Price for gas produced in any quarter after the Primary Term.
The Index Price for any quarter subsequent to the Primary Term, which expired December 31, 1999, is determined solely by reference to the Variable Price component. The Variable Price for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of (i) the final settlement prices per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal, for such contracts which expired in each of the five months prior to such month, (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in The Wall Street Journal, for such contracts which expire during such month and (iii) the closing settlement prices per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported in The Wall Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub which is traded on the New York Mercantile Exchange.
Under a standby performance agreement Eastern American has agreed to make payments under the Gas Purchase Contract to the extent such payments are not made by Eastern Marketing.
Supplemental Reserve Information (Unaudited):
Information regarding estimates of the proved gas reserves attributable to the Trust are based on reports prepared by independent petroleum engineering consultants. Such estimates were prepared in accordance with guidelines established by the Securities and Exchange Commission. Accordingly, the estimates were based on existing economic and operating conditions. Numerous uncertainties are inherent in estimating reserve volumes and values and such estimates are subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of these reserves may be substantially different from the original estimates.
The standardized measure of discounted future net cash flows was determined based on reserve estimates prepared by the independent petroleum engineering consultants. Fixed gas prices were used during the Primary Term, which ended December 31, 1999. The gas prices used thereafter are based solely on the fourth quarter Variable Price component.
The reserves and revenue values for the Underlying Properties transferred to the Trust were estimated from projections of reserves and revenue values attributable to the combined Eastern American and Trust interests in these properties. Reserve quantities are calculated differently for the Net Profits Interests because such interests do not entitle the Trust to a specific quantity of gas but to 90 % of the Net Proceeds derived therefrom. Accordingly, there is no precise method of allocating estimates of the quantities of proved reserves between those held by the Trust and the interests to be retained by Eastern American. For purposes of this presentation, the proved reserves attributable to the Net Profits Interests have been proportionately reduced to reflect the future estimated costs and expenses deducted in the calculation of Net Proceeds with respect to the Net Profits Interests. The reserves presented for the Net Profits Interests reflect quantities of gas that are free of future costs or expenses. The allocation of proved reserves between the Trust and Eastern American will vary in the future as relative estimates of future gross revenues and future costs and expenses vary.
The royalty portion of the Net Profits Interests was calculated beyond the liquidation date of the Trust (May 15, 2013), even though the terms of the Trust Agreement require that the Royalty Net Profits Interest be sold by the Trustee on or about this date and a liquidating distribution from the sales proceeds from such sale would be made to the Unitholders. The Term Net Profits Interests was limited to the 20-year period as defined by the Trust Agreement.
The following table reconciles the change in proved reserves attributable to the Trust’s share of the Net Profits Interests (“NPI”) from January 1, 2004 to December 31, 2006:
The Trust’s share of proved developed gas reserves are as follows:
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
The following is the standardized measure of discounted future net cash flows as of December 31, 2006 (in thousands):
The following is the standardized measure of discounted future net cash flows as of December 31, 2005 (in thousands):
The following is the standardized measure of discounted future net cash flows as of December 31, 2004 (in thousands):
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following schedule reconciles the changes during 2004, 2005 and 2006 in the standardized measure of discounted future net cash flows relating to proved reserves (in thousands):
Quarterly Financial Data (Unaudited):
The following is a summary of royalty income and distributable income per unit by quarter in 2006, 2005 and 2004 (all amounts in thousands except Distributable income per unit):