Item 1.
Business
Cautionary Statement
The Trustee (as defined below), its officers or its agents on behalf of the Trustee or Trust may, from time to time, make
forward-looking statements (meaning all 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 and elsewhere in this report involve a
number of risks and uncertainties. As a result of variations in such factors, actual results may differ materially from those contemplated by any forward-looking statements. The Trustee disclaims any
obligation to update forward-looking statements and all such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph and
elsewhere in this Report, including, without limitation, those contained below under the heading "Risk Factors."
Definitions
As used herein, the following terms have the meanings indicated: "Mcf" means thousand cubic feet of gas, "MMcf" means million cubic
feet of gas, "Bbl" means barrel (approximately 42 U.S. gallons), and "MBbl" means thousand barrels, "Btu" means British thermal units and "MMBtu" or "Dth" means million British thermal units.
The
following descriptions of Eastern American Natural Gas Trust (the "Trust"), the Depositary Units, the Net Profits Interests, the Underlying Properties and the calculation of amounts
payable to the Trust, are subject to and qualified in their entirety by the more detailed provisions of the Trust Agreement, the Depositary Agreement, the Conveyances and the Gas Purchase Contract
(each as defined below), all of which are incorporated by reference as exhibits to this Form 10-K and available upon request from the Trustee (as defined below) at the address set
forth herein. The information contained herein relating to the operations of the Underlying Properties, as well as information upon which the reserve figures and financial information contained herein
were derived, was furnished to The Bank of New York Mellon Trust Company, N.A., as trustee (the "Trustee") by Energy Corporation of America ("ECA").
DESCRIPTION OF THE TRUST
The Trust was formed under the Delaware Business Trust Act pursuant to a Trust Agreement (the "Trust Agreement") among Eastern American
Energy Corporation, as grantor, Bank of Montreal Trust Company, as trustee, and Wilmington Trust Company, as Delaware Trustee (the "Delaware Trustee").
The
Trust will sell its assets and liquidate prior to May 15, 2013 (the "Liquidation Date"). As described in the Trust's previous filings, the Trustee was required by the terms of
the Trust Agreement to cause the sale of the Royalty NPI held by the Trust (the "Royalty NPI"). In accordance with the requirements of the Trust Agreement, the Trustee marketed the Royalty NPI during
2012 and entered into a Purchase and Sale Agreement with the highest bidder for the Royalty NPI (the "October 24, 2012 Agreement"). On November 5, 2012, ECA exercised its right of first
refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of its right of first refusal, the
October 24, 2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24,
2012 Agreement. On January 3, 2013, the
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Trust
entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the October 24, 2012 Agreement that were
inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the adjustment for gas price changes required
by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash.
Pursuant
to the Trust Agreement, all proceeds of the sale of the Royalty NPI and all other receipts of the Trust received after December 31, 2012, will be retained by the Trustee
until a final distribution is made. Any final distribution will be subject to the prior payment of all expenses and liabilities of the Trust, and to the establishment and funding of any reserves the
Trustee deems appropriate for contingent liabilities. Unitholders as of the close of business on May 31, 2013 will, on or about June 17, 2013, as a result of the liquidation and winding
down of the Trust on May 15, 2013, receive the proceeds attributable to the mature Treasury Obligation ($20.00 per trust unit), unless the Treasury Obligation relating to such trust unit has
previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the Royalty
NPI (estimated to be approximately $0.95 per trust unit, based on net proceeds of approximately $5.65 million) plus their pro rata share of revenues attributable to the term net profits
interest for the period beginning October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the Units will be stopped at
the end of regular trading on the New York Stock Exchange (the "NYSE") at the close of business on May 31,
2013, and no transfers will be permitted after that date. See "Description of Trust Units and Depository UnitsLiquidation of the Trust."
On
February 13, 2013 ECA commenced an exchange offer in which ECA offered to exchange up to 4,120,059 units of ECA Marcellus Trust I, a Delaware statutory trust also sponsored by
ECA, for up to 3,197,385 Depositary Units of the Trust. The offer expired at 11:59 p.m. New York City Time, on March 13, 2013.
Until
March 26, 2012, Eastern Marketing Corporation was a wholly-owned subsidiary of Energy Corporation of America. Effective March 26, 2012, Eastern Marketing Corporation
was merged into Energy Corporation of America, with Energy Corporation of America being the surviving corporation. The merger of Eastern Marketing Corporation into its parent Energy Corporation of
America has not had any effect on the Trust.
Until
January 1, 2010, Eastern American Energy Corporation was a wholly-owned subsidiary of Energy Corporation of America. Effective January 1, 2010, Eastern American
Energy Corporation was merged into Energy Corporation of America, with Energy Corporation of America being the surviving corporation. Except as otherwise required by the context, references herein to
"ECA" mean Eastern American Energy Corporation at all times prior to January 1, 2010, and mean Energy Corporation of America at all times on and after January 1, 2010. The merger of
Eastern American Energy Corporation into its parent Energy Corporation of America has not had any effect on the Trust.
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 Trust Company, N.A. (now known as The
Bank of New York Mellon Trust Company, N.A.) as successor
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Trustee,
effective as of October 2, 2006. The transfer agent for the Trust is Bondholder Communications, an affiliate of The Bank of New York Mellon Trust Company, N.A.
The
Trust was formed to acquire and hold net profits interests (the "Net Profits Interests") created from the working interests owned by ECA in 650 producing gas wells and 65 proved
development well locations located in West Virginia and Pennsylvania (the "Underlying Properties"). A portion of the production from the wells burdened by the Net Profits Interests was intended to be
eligible for credits ("Section 29 Credits") under the Internal Revenue Code of 1986 for production of gas from Devonian shale or tight formations. The Net Profits Interests consisted of a
royalty interest in 322 wells and a term interest in the remaining wells and development well locations. ECA was obligated to drill and complete, at its expense, 65 development wells (the "Development
Wells") on the development well locations conveyed to the Trust. ECA has fulfilled its obligation with respect to the drilling of the Development Wells (see Note 1 of Financial Statements
included herewith). On or about May 15, 2013 (the "Liquidation Date"), the Trustee is required to sell the remaining royalty interests and begin the liquidation of the Trust. As described
herein, the Trust completed the sale of the Royalty NPI on January 10, 2013. Because ECA acquired the rights to the distribution for the fourth quarter of 2012, the sale had an effective date
of October 1, 2012. The Trust's remaining net profits interest is a Term NPI, which will terminate by its terms on May 15, 2013, and revert to ECA, and the Trust will receive no further
value from the Term NPI after that date.
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. Holders of Depositary Units ("Unitholders") may withdraw the Treasury Obligations associated with the Trust Units (see "Description
of Trust Units and Depositary Units"). 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 retained by ECA
in 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
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 Underlying Properties (defined above) 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; and 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.
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 fees paid to the Trustee for 2012 were $108,000. The total of all Trustee fees and Trust administrative expenses for 2012 was $1,017,119. Such costs could
fluctuate in 2013 depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, and may be materially higher during 2013 than
they have been in the past as the Trust incurs expenses in connection with its liquidation in accordance with the Trust Agreement. In addition to such expenses, in 2012, the Trust paid ECA an overhead
reimbursement of $403,724. The overhead reimbursement was established at the inception of the Trust, increased by 3.5% per year, and is payable quarterly.
Unitholders
as of the close of business on May 31, 2013 will, on or about June 17, 2013, as a result of the liquidation and winding down of the Trust beginning on
May 15, 2013, receive the proceeds attributable to the mature Treasury Obligation ($20.00 per trust unit) unless the Treasury Obligations
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have
previously been withdrawn. On or about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the
Royalty NPI (estimated to be approximately $0.95 per trust unit, based on net proceeds of $5.65 million) plus their pro rata share of revenues attributable to the Term NPI for the period
beginning October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the trust units will be stopped at the end of regular
trading on the NYSE at the close of business on May 31, 2013, and no transfers will be permitted after that date.
THE NET PROFITS INTERESTS
The Conveyances
The Net Profits Interests ("NPI") were created from the Underlying Properties and conveyed to the Trust pursuant to two
Conveyancesone conveying a royalty interest in specified wells (the "Royalty NPI Conveyance") and the other conveying a term interest in specified wells (the "Term NPI Conveyance", and
together with the Royalty NPI Conveyance, the "Conveyances"). As described herein, the Trust sold its interest under the Royalty NPI Conveyance, including the right to the distribution for the fourth
quarter of 2012, to ECA for $5.9 million on January 10, 2013, and the Trust's interest under the Term NPI Conveyance will terminate by its terms on May 15, 2013, and the Trust
will receive no further value from it after that date. Forms of the Conveyances have been filed as exhibits to this Form 10-K.
The
Underlying Properties are subject to and burdened by the Net Profits Interests. The interests of ECA comprising the Underlying Properties represented, on average, a working interest
of approximately 90% and a net revenue interest of approximately 76%. The Conveyances provide that the Trust is only entitled to gas produced from the specific wells identified in the Conveyances and
is
not entitled to any gas produced from adjacent wells (including adjacent wells subject to the same lease or farmout agreement as the wells subject to the Net Profits Interests). Gas produced from the
Underlying Properties which is attributable to the Net Profits Interests is purchased from the Trust by ECA as successor to Eastern Marketing pursuant to a gas purchase contract (the "Gas Purchase
Contract"). The volumes attributable to the Net Profits Interests and the purchase price for such gas is calculated for each calendar quarter, and payment for such gas is made to the Trust not later
than the tenth day of the third calendar month following the end of each calendar quarter.
The
Trust will terminate in 2013. See "Description of Trust Units and Depository UnitsLiquidation of the Trust."
The
Term NPI will expire on the earlier of May 15, 2013 or such time as 41,683 MMcf has been produced which is attributable to ECA's net revenue interests in the properties
burdened by the Term NPI. As of December 31, 2012, 28,239 MMcf of such gas had been produced. Consequently, the Term NPI will terminate on May 15, 2013.
The
Royalty NPI was not limited in term or amount. Under the Trust Agreement, the Trustee was directed to sell the Royalty NPI after May 15, 2012 and prior to May 15, 2013,
and has done so.
ECA
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, ECA 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. Prior to January 1, 2010, the limitations on ECA's right to transfer a portion of the Underlying Properties included limitations on the aggregate sales proceeds
for any such sales. As of January 1, 2010, the limitations on the aggregate sales proceeds no longer apply. 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. See "Sale and Abandonment of Underlying Properties."
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Calculation of Net Proceeds
The definitions, formulas, accounting procedures and other terms governing the computation of Net Proceeds are detailed and extensive,
and reference is made to both the Royalty NPI Conveyance and the Term NPI Conveyance for a more detailed discussion of the computation thereof. As described herein, the Trust has sold its interest
under the Royalty NPI Conveyance.
The
Conveyances and the Gas Purchase Contract entitle the Trust to receive an amount of cash for each calendar quarter equal to the Net Proceeds for such quarter. "Net Proceeds" for any
calendar quarter generally means an amount of cash equal to (a) 90% of a volume of gas equal to (i) the volume of gas produced during such quarter attributable to the Underlying
Properties less (ii) a volume of gas equal to Chargeable Costs, as defined below, for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase
Contract. If, for any reason, the Gas Purchase Contract terminates prior to the Liquidation Date, "Net Proceeds" will mean an amount of cash equal to (a) 90% of a volume of gas equal to
(i) the volume of gas produced during such quarter attributable to the Underlying Properties less (ii) a volume of gas equal to Chargeable Costs for such quarter, multiplied by
(b) the applicable price for such quarter determined in accordance with the Conveyances. Pursuant to the Conveyances, the Trust is not entitled to receive any natural gas liquids produced from
the Underlying Properties or any proceeds relating thereto.
"Chargeable
Costs" is that volume of gas which equates in value, determined by reference to the relevant sales price under the Gas Purchase Contract or the Conveyances, as applicable, to
the sum of the "Operating Cost Charge", "Capital Costs" and "Taxes" (as defined in the Conveyances). The Operating Cost Charge at the beginning of the year 2012 was estimated to be $599,556, for 2011
was $658,604 and for 2010 was $658,604. The 2012 Operating Cost Charge was decreased during the quarter ended December 31, 2012 as a result of wells sold during the fourth quarter. The 2011
Operating Cost Charge was decreased during the quarter ended June 30, 2011 as a result of wells sold during the second quarter. As provided in the Conveyances, the Operating Cost Charge will
increase based on the lesser of (A) five percent (5%) or (B) a percentage, not less than zero percent (0%), equal to the percentage increase, if any, in the average weekly earnings of
Crude Petroleum and Gas Production Workers for the last calendar year, as shown by the index of average weekly earnings of Crude Petroleum and Gas Production Workers, as published by the United States
Department of Labor, Bureau of Labor Statistics, based on December-to-December comparison.
During
2003, the United States Department of Labor, Bureau of Labor Statistics converted all of its industry-based statistics to a different reporting system that was developed in
cooperation with the United States' North American Free Trade Agreement Partners, Canada and Mexico, in an effort to standardize and modernize reporting codes. As a result of this conversion, the
Crude Petroleum and Gas Production Workers index is no longer available for use in the annual calculation of overhead adjustment called for in the various Council of Petroleum Accountants Societies,
or COPAS, model forms after March 2003.
Research
by COPAS covering a ten year period indicated that by blending the Oil and Gas Extraction Index with the Professional and Technical Services Index, the results approximate the
data from the old Crude Petroleum and Natural Gas Workers Index. Accordingly, COPAS has calculated the percentage change in the simple average of the Oil and Extraction Index and the Professional and
Technical Services Index, commencing in April 2004. This "Overhead Adjustment Index" has been provided as a guidance to the industry as a replacement index for use in calculating the overhead
adjustment. Due to the "Overhead Adjustment Index" being -0.7%, the adjustment for the effective time period is 0%. As discussed above, the Operating Cost Charge will increase based on the
lesser of (A) five percent (5%) or (B) a percentage, not less than zero percent (0%). Since the Conveyance Documents do not specifically provide for a replacement index if the Crude
Petroleum and Gas Production Workers Index was no longer published, ECA believes, and advised the Trustee, that the "Overhead Adjustment Index" as calculated by COPAS is a reasonable index to utilize
since the
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industry
is generally adopting the same as a replacement. ECA, with the concurrence of the Trustee, will utilize this "Overhead Adjustment Index" to adjust the "Operating Cost Charge" so long as such
index is published by COPAS.
The
Operating Cost Charge will be reduced for each well that is sold (free of the Net Profits Interests) or plugged and abandoned. Capital Costs are defined as ECA's working interest
share of capital costs for operations on the Underlying Properties having a useful life of at least three years, and excluding any capital costs incurred in drilling the Development Wells. Taxes refer
to ad valorem taxes, production and severance taxes, and other taxes imposed on ECA's or the Trust's interests in the Underlying Properties, or production therefrom.
Although
the Trust bears the full economic burden of Chargeable Costs, it does so indirectly in the calculation of Net Proceeds and the Trust is not directly liable for any share of the
costs, risks, and liabilities associated with the ownership or operation of the Underlying Properties. If the Trust ever receives payments in excess of the Net Proceeds or other amounts it was not
entitled to receive, the Trust will not be required to refund the money, but ECA may recover the amount of such overpayments from future distributions in accordance with the Conveyances.
The
Conveyances require ECA to maintain books, records, and accounts sufficient to calculate the volumes of gas and the share of Net Proceeds payable to the Trust. ECA provides to the
Trust quarterly and annual statements of applicable production, revenues, and costs necessary for the Trust to prepare quarterly and annual financial statements with respect to the Net Profits
Interests and the Underlying Properties. The financial statements of the Trust are audited annually at the Trust's expense.
Gas Purchase Contract
Gas production attributable to the Net Profits Interests was originally purchased by Eastern Marketing (which merged into ECA during
2012) pursuant to the Gas Purchase Contract which effectively commenced as of January 1, 1993 and expires upon the termination of the Trust.
Under
the Gas Purchase Contract, ECA, as successor by merger to Eastern Marketing, purchases gas for the benefit of the Trust at a variable price for each 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 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.
The
purchase price pursuant to the Gas Purchase Contract is a wellhead price and title to the gas purchased passes at the point of delivery. Payments to the Trust are made by ECA on or
before the tenth day of the third calendar month following the end of each calendar quarter.
The
Trust Agreement provides that the Trustee may not agree to any amendment to the Gas Purchase Contract which would materially and adversely affect the revenues to the Trust without
the approval of the holders of a majority of the outstanding Trust Units. The Trust Agreement also
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provides
that the Gas Purchase Contract may not be terminated by the Trust without the approval of the holders of a majority of the outstanding Trust Units. The Gas Purchase Contract and the Trust
Agreement have been filed as exhibits to this Form 10-K. The foregoing summary of the
principal provisions of the Gas Purchase Contract and certain provisions of the Trust Agreement is qualified in its entirety by reference to the terms of such agreements as set forth in such exhibits.
ECA's
rights and obligations under the Gas Purchase Contract are assignable under circumstances where the assignee unconditionally assumes ECA's obligations under the Gas Purchase
Contract only if such assignee (or assignee's parent corporation if such parent guarantees the assignee's obligations) has a rating assigned to its unsecured long-term debt by Moody's
Investor Service of at least Baa+ and by Standard & Poor's Corporation of at least BBB-. Under such circumstances, ECA would be released from its obligations under the Gas Purchase
Contract.
Distributions and Income Computations
The Trustee determines for each quarter the amount of cash available for distribution to holders of Depositary Units and the Trust
Units evidenced thereby. Such amount (the "Quarterly Distribution Amount") is equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month
after the end of each calendar quarter ending before the Trust is dissolved and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus,
with certain exceptions, any other cash receipts of the Trust during such quarter, over (ii) 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 for the payment of contingent or future obligations of the Trust. Quarterly Distribution Amounts per unit for each of the quarters in
2012 were $0.1457, $0.1352, $0.1330 and $0.0000, respectively. Based on the payment procedures relating to the Net Profits Interests, cash received by the Trustee in a particular quarter from the Net
Profits Interests reflects 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. The Quarterly Distribution Amount for each quarter generally is payable to Unitholders of record on the last day of the second month following the end of such calendar quarter or
such later date as the Trustee determines is required to comply with legal or stock exchange requirements ("Quarterly Record Date"). The Trust has sold the Royalty NPI assets and will begin to
liquidate in May 2013. Pursuant to the Trust Agreement, all receipts of the Trust received after December 31, 2012, will be retained by the Trustee until a final distribution to be made on or
about August 15, 2013. Any final distribution will be subject to the prior payment of all expenses and liabilities of the Trust, and to the establishment and funding of any reserves the Trustee
deems appropriate for contingent liabilities. See "Description of Trust Units and Depository UnitsLiquidation of the Trust."
The
net taxable income of the Trust for each calendar quarter is reported by the Trustee for tax purposes as belonging to the holders of record to whom the Quarterly Distribution Amount
was or will be distributed. Assuming that the Trust will be classified for tax purposes as a "grantor trust," the net taxable income will be realized by the holders for tax purposes in the calendar
quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Thus, a Unitholder's taxable income for a taxable year may differ from the cash the Unitholder receives during
that year. In addition, taxable income of a holder will differ from the Quarterly Distribution Amount because the Treasury Obligations will be treated as generating interest income for tax purposes.
There may also be minor
variances because of the possibilities that a reserve will be established in one quarter that will not give rise to a tax deduction until a subsequent quarter, an expenditure paid for in one quarter
will have to be amortized for tax purposes over several quarters, or for other reasons. See "Federal Income Tax Matters."
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Sale and Abandonment of Underlying Properties
ECA and any transferees have the right to abandon any well or working interest included in the Underlying Properties if, in its
opinion, such well or property ceases to produce or is not capable of producing in commercially paying quantities. To reduce or eliminate the potential conflict of interest between ECA and the Trust
in determining whether a well is capable of producing in paying quantities, ECA is required under the Conveyances to make any such determination as would a reasonably prudent operator in the
Appalachian Basin if it were acting with respect to its own properties, disregarding (i) the existence of the Net Profits Interests as a burden on such property and (ii) the direct or
indirect effect, financial or otherwise, on ECA or any of its affiliates that may result from the performance by Eastern Marketing, and now with ECA as successor by merger, of its obligations under
the Gas Purchase Contract.
ECA
has the right, pursuant to the Conveyances, to sell all or any portion of the Underlying Properties without restrictions and without the consent of the Trust or the Unitholders;
however, the purchaser of any of the Underlying Properties will acquire such Underlying Properties subject to the Net Profits Interests relating thereto (except in certain circumstances where the
Trust may be required to release the Net Profits Interests, subject to its receipt of the fair value thereof). Any such purchaser will be
subject to the same standards of conduct with respect to development, operation and abandonment of such Underlying Properties as set forth in the preceding paragraph.
ECA
may sell the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the Trust or the Unitholders. Any releases by the Trust are
conditioned upon the Trust receiving an amount equal to the fair value (as defined in the Trust Agreement) to the Trust of its Net Profits Interests (taking into account the relevant market conditions
and factors existing at the time of the sale. Any proceeds paid to the Trust are distributable to Unitholders for the quarter in which they are received
During
the first half of 2011, ECA entered into two separate Purchase and Sale Agreements to sell certain assets in which the Trust owned a Net Profits Interest to unrelated third
parties. ECA finalized the sale of the assets, as described in the Purchase and Sale Agreements, in the quarter ended June 30, 2011. ECA received sale proceeds for the wells in the amount of
$588,911. The Trust's share of the sales proceeds was $181,928 and was included in the Distributable Income of the Trust during the quarter ended June 30, 2011. No other sale of assets in which
the Trust owned a Net Profits Interest occurred in 2011.
THE UNDERLYING PROPERTIES
General
The Underlying Properties are comprised of ECA's working interests in certain properties located in the Appalachian Basin states of
West Virginia and Pennsylvania. As of December 31, 2012, such properties consisted of 329 producing gas wells. The working interests of ECA comprising the Underlying Properties are held under
leases and farmout agreements with third parties. Such working interests are subject to landowner's royalties (typically 12.5%) and may be subject to additional royalties or other obligations
burdening the working interests. Such royalties do not bear lease operating expenses, but reduce the revenue interests attributable to the Underlying Properties.
The
Appalachian Basin is a mature producing region with well known geologic characteristics. Substantially all of the wells comprising the Underlying Properties are relatively shallow,
ranging from 2,500 to 5,500 feet, and many are completed to multiple producing zones. In general, the wells to which the Underlying Properties relate are proved producing properties with stable
production profiles and
generally long-lived production, often with total projected economic lives in excess of 25 years. Once
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drilled
and completed, ongoing operating and maintenance requirements are low and only minimal, if any, capital expenditures are typically required.
The
Underlying Properties initially included 65 specified development well locations for the drilling of the Development Wells by ECA. ECA was obligated to bear the costs of drilling and
completing the Development Wells. ECA has fulfilled its obligation with respect to the drilling of the Development Wells. See Note 1 of Financial Statements.
ECA
acquired its interests in the Underlying Properties under or through (i) oil and gas leases granted by the mineral owner directly to ECA, (ii) assignments of oil and
gas leases by the lessee who originally obtained the leases from the mineral owner, (iii) farmout agreements that grant ECA the right to earn interests in the properties covered by such
agreements by drilling wells and (iv) the acquisitions of oil and gas interests by ECA.
Production
from the wells to which the Underlying Properties relate is typically subject to (i) landowner royalties and other burdens and obligations retained under oil and gas
leases, (ii) overriding royalty interests and (iii) interests of other working interest owners in the wells. The royalty and overriding interests entitle the holders thereof to a certain
percentage of the oil and gas produced from the wells or the proceeds therefrom and are generally delivered free of all expenses of production but may be subject to post-production costs,
such as production or gathering taxes, costs to treat the gas to render it marketable, and certain transportation or gathering costs. Royalty interests are usually reserved by the lessor under an oil
and gas lease. Overriding royalty interests are carved out of a lessee's share of production under an oil and gas lease and are generally reserved by a predecessor in title or reserved under farmout
agreements.
A
farmout agreement is typically an agreement under which a lessee under an oil and gas lease (the "Farmor") grants to another party the right to drill wells on the tract covered by such
lease and to earn certain acreage for drilling such wells. In the Appalachian Basin, the Farmor generally receives a well location fee and reserves an overriding royalty interest in the wells which
typically ranges from 3.25% to 6.25%. Farmout agreements typically provide that wells must be drilled and completed as a condition to a transfer by the Farmor of the interest in the underlying lease.
Reserves
Proved Reserves of Underlying Properties and Net Profits Interests.
The following table sets forth, as of December 31, 2012,
certain estimated
proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, and the Term NPI, in each case derived from a report of oil and gas
reserves attributable to the Trust as of December 31, 2012 prepared by Ryder Scott Company (the "Reserve Report"). The Reserve Report and the table below do not include any interest or amount
attributable to the Royalty NPI, which the Trust sold in January 2013, with an effective date of October 1, 2012, as described herein. Proved reserve quantities attributable to the Net Profits
Interests are calculated by subtracting an amount of gas sufficient, if sold at the prices used in preparing the reserve estimates, to pay the future estimated costs and expenses deducted in the
calculation of Net Proceeds. Accordingly, the reserves attributable to the Net Profits Interests reflect quantities of gas that are free of future costs or expenses if the price and cost assumptions
set forth in the Reserve Report occur. A decrease in the price assumption, or an increase in the cost assumption used in the Reserve Report would reduce the estimates of proved reserves, future net
revenues and discounted future net revenues, set forth herein and in the Reserve Report. The Term NPI excludes production beyond the earlier of May 15, 2013 or such time as 41,683 MMcf has been
produced which is attributable to ECA's net revenue interests in the properties burdened by the Term NPI. The discounted present value of estimated future net revenues was determined using a
11
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discount
rate of 10% in accordance with applicable requirements. A summary of the Reserve Report is included as Annex A hereto.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Gas Reserves
|
|
|
|
|
|
|
|
|
|
Discounted
Estimated
Future Net
Revenues(2)
|
|
|
|
Developed
|
|
(MMcf)
Undeveloped
|
|
Total
|
|
Estimated
Future Net
Revenues(2)
|
|
|
|
|
|
|
|
|
|
(Dollars in thousands)
|
|
Underlying Properties(1)
|
|
|
14,210
|
|
|
0
|
|
|
14,210
|
|
$
|
34,740
|
|
$
|
14,883
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Profits Interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term NPI
|
|
|
226
|
|
|
0
|
|
|
226
|
|
|
814
|
|
|
796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
226
|
|
|
0
|
|
|
226
|
|
$
|
814
|
|
$
|
796
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Reserve
volumes and estimated future net revenues for Underlying Properties reflect volumes and revenues distributable to ECA's entire net revenue interest
with respect to the Underlying Properties.
-
(2)
-
The
effects of depreciation, depletion and federal income tax have not been taken into account in estimating future net revenues. Estimated future net
revenues and discounted estimated future net revenues are not intended, and should not be interpreted, as representing the fair market value for the estimated reserves.
There
are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the timing of development expenditures, if
any. The reserve data set forth herein, although prepared by independent engineers in a manner customary in the industry, are estimates only, and actual quantities and values of gas are likely to
differ from the estimated amounts set forth herein. In addition, the discounted present values shown herein were prepared using guidelines established by the Securities and Exchange Commission (the
"Commission") and the Financial Accounting Standards Board for disclosure of reserves and should not be considered representative of the market value of such reserves or the Depositary Units or the
Trust Units evidenced thereby. A market value determination would include many additional factors.
Preparation of reserve report.
As described in this Report, the interests held by the Trust consist of a net profits interest derived from working and royalty
interests. The net profits interest does not entitle the Trust to a specific quantity of oil or gas but to 90 percent of the net proceeds of the relevant production.
The
Trust retained Ryder Scott Company L.P. ("Ryder Scott"), which is an independent petroleum engineering consulting firm that has been providing petroleum consulting services
throughout the world for over seventy years, to prepare a third-party report of the reserves attributable to the net profits interest. A signed copy of the report, dated January 11, 2013, (the
"Reserve Report"), is attached as Annex A to this Report on Form 10-K and filed as exhibit 99.1. As stated in the Reserve Report, the estimates contained therein are
based on accounts, records, geological and engineering data and reports and other data provided to Ryder Scott by ECA and are based on data available through September 2012. The Trust has no access
to, and its internal controls do not cover, the geological, engineering or other data and information provided by ECA to Ryder Scott in connection with the preparation of the Reserve Report. The
qualifications of Mr. Stephen E. Gardner, the technical person primarily responsible for overseeing the preparation of the Reserve Report are as follows. Mr. Gardner, an employee of
Ryder Scott since 2006, is a Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions
with Exxon Mobil Corporation. Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is licensed
12
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Professional
Engineer in the States of Colorado and Texas. He is also a member of the Society of Petroleum Engineers. As part of his 2012 continuing education hours, Mr. Gardner attended a six
hour conference relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange commission Title 17, Code of Federal Regulations, Modernization of Oil and
Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. In May 2012, Mr. Gardner attended the DUO Conference in Denver, Colorado, which focused on developed and
emerging unconventional oil plays and on current issues in energy. In addition, Mr. Gardner attended an SPEE luncheon regarding valuation metrics in the Bakken play and Permian Basin. Finally,
Mr. Gardner completed several days of informal study that included such topics as SPEE Monograph 3, utilization of economics evaluation softwares, and principles of waterflooding.
The
Reserve Report was prepared for the Trust primarily to comply with the requirements of the Amended and Restated Trust Agreement pursuant to which the Trust was originally created. It
was completed on January 11, 2013 and has an effective date of December 31, 2012. The report covers all of the registrant's interest in the net profits interest. The properties to which
the net profits interest relate are located in the United States, specifically in West Virginia and Pennsylvania. The estimated reserves and future net income amounts presented in the Reserve Report,
as of December 31, 2012 are related to hydrocarbon prices, computed in accordance with the gas contract described below and applicable SEC rules. The hydrocarbon prices used in the preparation
of the Reserve Report are based on the average prices during the 12-month period prior to the ending date of the period covered in the Reserve Report, determined as unweighted arithmetic
averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements
as required by the SEC regulations. For purposes of the Reserve Report, the proved reserves attributable to the net profits interest have been proportionately reduced to reflect the future estimated
costs and expenses deducted in the calculation of Net Proceeds. Accordingly, the reserves presented reflect quantities of gas that are free of future costs or expenses based on the price and cost
assumptions utilized in the Reserve Report. The Reserve Report utilized the terms of the gas contract between Eastern Marketing, and now with
ECA as successor by merger, and the Trust. Under the gas contract, the Trust receives the Henry Hub Average Spot Price (defined as described below) 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 Trust believes that the assumptions, data, methods and procedures utilized by Ryder Scott are appropriate for the purpose served by the Reserve Report, and
believes that Ryder Scott has used all methods and procedures Ryder Scott considered necessary under the circumstances to prepare the Reserve Report.
Internal Controls.
Ryder Scott prepared its report as described above in accordance with appropriate engineering, geologic, and
evaluation principles
and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves, estimation methods and
techniques are widely taught in university petroleum curricula and throughout the industry's ongoing training programs. Although these appropriate engineering, geologic, and evaluation principles and
techniques that are in accordance with practices generally accepted in the petroleum industry are based upon established scientific concepts, the application of such principles involves extensive
judgment and is subject to changes in existing
13
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knowledge
and technology, economic conditions and applicable statutory and regulatory provisions. The same industry wide applied techniques are used in determining estimated reserve quantities. The
technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the
Society of Petroleum Engineering Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. ECA has advised the Trust that it maintains adequate controls over the
underlying data it provides to Ryder Scott, which is designed to result in accurate and reliable data in compliance with applicable regulations and guidance. The data ECA furnishes to Ryder Scott is
reviewed by staff reservoir engineers and geoscientists before review by the Reservoir Engineering Manager and finally the Chief Operating Officer. These individuals consult regularly with Ryder Scott
during Ryder Scott's reserve estimation process to review properties, assumptions, and any new data available. ECA's Reservoir Engineering Manager has a Bachelor of Science degree in Petroleum
Engineering. He has over six years of oil and gas industry experience in reservoir engineering. ECA's Chief Operating Officer is the primary technical person responsible for overseeing the data
reporting process. This individual has a Bachelor of Science degree in Chemical Engineering with Masters of Petroleum Engineering coursework along with a Master of Business Administration degree. He
has
worked in drilling, completions, production, and reservoir engineering along with acquisitions during his career and is a member of the Society of Petroleum Engineers. He has over nine years of
experience in reserve evaluation.
A
brief summary of Ryder Scott's conclusions with respect to the matters covered by the Reserve Report is set forth above under "
Proved Reserves of Underlying
Properties and Net Profits Interests.
" Other matters, including a discussion of the inherent uncertainties of reserves estimates, are also contained elsewhere in this Report on
Form 10-K and in the Reserve Report.
COMPETITION AND MARKETS
All of the production attributable to the Net Profits Interest is sold to ECA, as successor to Eastern Marketing, pursuant to the Gas
Purchase Contract. See "The Net Profits InterestsGas Purchase Contract."
The
natural gas industry is highly competitive. ECA competes with major oil and gas companies and independent oil and gas companies for oil and gas leases, equipment, personnel and
markets for the sale of natural gas. Many of these competitors are financially stronger than ECA, but even financially troubled competitors can affect the market because they may need to sell natural
gas regardless of price to attempt to maintain cash flow. The Trust is subject to the same competitive conditions as ECA and other companies in the natural gas industry.
Natural
gas competes with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of
energy may affect the demand for natural gas.
Future
price fluctuations for natural gas will directly affect Trust distributions, estimates of reserves attributable to the Trust's interests, and estimated and actual future net
revenues to the Trust. In view of the many uncertainties that affect the supply and demand for natural gas, neither the Trust nor ECA can make reliable predictions of future gas supply or demand,
future gas prices or the effect of future gas prices on the Trust.
14
Table of Contents
REGULATION OF NATURAL GAS
The natural gas industry has historically been highly regulated by state and federal authorities. In the past, concerns about perceived
pipeline monopolies and other factors caused Congress to impose economic regulation on both pipelines and producers. Federal agencies regulated tariffs and conditions of service offered by interstate
pipelines, and set maximum prices on the wellhead price of natural gas sold into interstate commerce. States, and even local governments, also regulated retail sales of natural gas by local utilities.
Government agencies also set production rates to avoid waste and imposed environmental and safety regulations. At present, it appears that Federal regulation of wellhead natural gas prices has ended.
However, there can be no assurance that price controls or other similar economic regulations may not be reimposed in the future.
Drilling
and production of natural gas are heavily regulated in Pennsylvania and West Virginia, as in most states. A well cannot be drilled without a permit, and operations must be
conducted in compliance with environmental, safety and conservation laws and regulations. In contrast to many other states which have substantial oil and gas production activity, the spacing of
shallow wells (such as the wells subject to the Net Profits Interests) is not regulated by any state statute or regulatory agency in either West Virginia or Pennsylvania. Without spacing requirements
specified by state statute or regulation, drainage of reserves from a property may occur from wells located in close proximity to such property.
HEALTH, SAFETY, AND ENVIRONMENTAL REGULATION
General.
Activities at the Underlying Properties are subject to existing Federal, state and local laws and regulations governing health,
safety,
environmental quality and pollution control. It is anticipated that, absent the occurrence of an extraordinary event, compliance with such laws and regulations will not have a material adverse effect
upon the Trust. It cannot be predicted what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the
environment resulting from operations at the Underlying Properties could have on the
Trust. However, pursuant to the terms of the Conveyances, any costs or expenses incurred in connection with environmental liabilities of ECA arising out of or related to activities occurring at or
from, or conditions existing at, on or under, the Underlying Properties before the effective date of the Conveyances will be borne by ECA and will not be deducted in calculating Net Proceeds
attributable to the Net Profits Interests. Additionally, because Unitholders are expected to have limited liability in accordance with the Trust Agreement and Delaware law, Unitholders are expect to
be shielded from direct liability for any environmental liabilities. See "Description of Trust Units and Depositary UnitsLiability of Unitholders." However, costs and expenses incurred by
ECA for certain Capital Costs associated with environmental laws or regulations arising after the effective date of the Conveyances would reduce Net Proceeds, and would therefore be borne, in part, by
the Unitholders. The following subtopics discuss some of the principal forms of health, safety, and environmental regulation to which the Underlying Properties and operations thereon are subject. The
costs of complying with these regulatory requirements may burden the Net Profits Interests to the extent they arise out of or are related to activities occurring at or from, or conditions existing at
or from, the Underlying Properties after the effective date of the Conveyances.
Solid and Hazardous Waste.
The Underlying Properties include numerous properties that have produced gas for a number of years but in
which ECA has
held an interest for a relatively short period of time prior to the effective date of the Conveyances. ECA has no knowledge of prior operators utilizing operating and disposal practices that were not
standard in the industry at the time or that hydrocarbons or other solid or hazardous wastes have been disposed of or released at or from the Underlying Properties. Federal, state and local laws
applicable to drilling-, completion- and production-related wastes have become increasingly more stringent. Under current laws, ECA or the operator of the Underlying Properties could be required to
remove or remediate previously disposed wastes or
15
Table of Contents
property
contamination (including groundwater contamination) or to perform remedial plugging operations to reduce the likelihood of future contamination.
The
operations of the Underlying Properties may generate wastes that are subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The
Environmental Protection Agency (the "EPA") has limited the disposal options for certain hazardous wastes and may adopt more stringent disposal standards for nonhazardous wastes.
Superfund
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund" law, imposes
strict, joint and several liability, regardless of fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous
substance" into the environment. These persons include the current or previous owner and operator of a site and companies that disposed, or arranged for the disposal of,
hazardous substance at any site where such a release has occurred. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the
environment and to seek recovery from such responsible classes of persons of the costs of such action. In the course of their operations, the operators of the Underlying Properties have generated and
will generate wastes that may fall within CERCLA's definition of "hazardous substances." ECA or the previous operator of the Underlying Properties may be responsible under CERCLA for all or part of
the costs to clean up sites at which such substances have been released.
Air Emissions.
The operations of the Underlying Properties are subject to Federal, state and local regulations concerning the control of
emissions
from sources of air contaminants. Administrative enforcement actions for failure to comply strictly with air regulations or permits are generally resolved by payment of a monetary penalty and
correction of any identified deficiencies. Regulatory agencies could require the operators to obtain pre-approval for, forego or modify construction or operation of certain air emission
sources.
On
December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the
environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. These findings allow the EPA to adopt and implement
regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that could trigger permit review for GHG
emissions from certain stationary sources. The EPA has also issued regulations that require the establishment and reporting of an inventory of GHG emissions from specified stationary sources,
including certain onshore oil and natural gas exploration, development and production facilities. These regulations could require ECA to incur costs to reduce emissions of GHGs associated with its
operations or could adversely affect demand for the natural gas it produces. In addition, certain states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the
planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as
coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.
Endangered Species Act.
The federal Endangered Species Act, as amended ("ESA"), restricts activities that may affect endangered and
threatened
species or their habitats. The designation of previously unidentified endangered or threatened species could cause ECA to incur additional costs or become subject to operating restrictions or bans in
the affected areas.
Water Discharges.
The Federal Water Pollution Control Act, as amended ("Clean Water Act"), and analogous state laws impose restrictions
and strict
controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be
16
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obtained
to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit
issued by EPA or the analogous state agency. If ECA or the operator of the Underlying Properties is unable to remove and dispose of water at a reasonable cost and within applicable environmental
rules, the ability to produce gas commercially and in commercial quantities from the Underlying Properties could be impaired. Spill prevention, control and countermeasure requirements under federal
law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition,
the Clean Water Act and analogous state laws, including in Pennsylvania and West Virginia, require individual permits or coverage under general permits for discharges of storm water runoff from
certain types of facilities.
State regulation.
States regulations may apply to the drilling for, and the production, gathering and sale of, natural gas, including
imposing
requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells, production rates and the prevention of waste of natural gas resources. The
imposition of more stringent state regulations on ECA's operations could require ECA to incur increased operating costs.
OSHA.
The operations of the Underlying Properties are subject to the requirements of the Federal Occupational Safety and Health Act
("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act and similar state statutes require that information be organized and maintained about hazardous materials used or produced in the operations. Certain of this information must be
provided to employees, state and local government authorities and citizens.
DESCRIPTION OF TRUST UNITS AND DEPOSITARY UNITS
The following information is subject to the detailed provisions of the Deposit Agreement originally entered into by ECA, the Trustee,
and Bank of Montreal Trust Company, as Depositary (the "Depositary") and all holders from time to time of Depositary Units (the "Deposit Agreement"), a copy of which is filed as an exhibit to this
Form 10-K.
The
functions of the Depositary under the Deposit Agreement are custodial and ministerial in nature and for the benefit of Unitholders. The Deposit Agreement and the issuance of
Depositary Units thereunder provide Unitholders an administratively convenient form of holding an investment in the Trust and a Treasury Obligation. Each Depositary Unit is evidenced by a certificate,
which is issued by the Depositary and transferable only in denominations of 50 Depositary Units or an integral multiple thereof. Accordingly, each holder of 50 Depositary Units owns a beneficial
interest in 50 Trust Units and the entire beneficial interest in a discrete Treasury Obligation in a face amount of $1,000, or $20 per Depositary Unit.
The
deposited Trust Units and Treasury Obligations are held solely for the benefit of the Unitholders and do not constitute assets of the Depositary or the Trust. The Depositary has no
power to assign, transfer, pledge or otherwise dispose of any of the Trust Units or Treasury Obligations, except in the limited instances provided in the Deposit Agreement.
Generally,
the holders of Depositary Units are entitled to participate in distributions with respect to the Trust Units, the Treasury Obligations and to the liquidation of the remaining
assets of the Trust.
Withdrawal of Trust Units and Restrictions on Transfer
Upon presentation of Depositary Units in denominations of 50 or integral multiples thereof for withdrawal of the Trust Units and
discrete Treasury Obligations evidenced thereby in accordance with
17
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the
Deposit Agreement, the Unitholder will receive an uncertificated direct interest in Trust Units. These withdrawn Trust Units will be evidenced on the books of the Trustee by a transfer of such
Trust Units from the name of the Depositary to the name of the withdrawing Unitholder. Holders of withdrawn Trust Units will be entitled to receive Trust distributions and periodic Trust information
(including tax information) directly from the Trustee. Moreover, holders of Trust Units will be entitled to each of the rights accorded Unitholders under the Trust Agreement, including voting and
liquidation rights, as elsewhere described herein, except that withdrawn Trust Units are not freely transferable as described below.
Pursuant
to the Trust Agreement and the transfer application for transfer of the Trust Units, withdrawn Trust Units are not transferable except by operation of law. A holder of withdrawn
Trust Units may, however, transfer such Trust Units in denominations of 50 (or integral multiples thereof) to the Depositary for redeposit, together with Treasury Obligations in the face amount equal
to $1,000 for each 50 Trust Units redeposited, in exchange for Depositary Units. Such redeposit may be effected by delivering written notice of such transfer jointly to the Depositary and the Trustee
together with proper documentation necessary to transfer the requisite Treasury Obligations into the name of the Depositary.
Distributions and Income Computations
Subject to the procedures set forth in the Trust Agreement relating to the pending liquidation of the Trust, the Trustee determines for
each quarter the Quarterly Distribution Amount available for distribution to holders of Depositary Units and the Trust Units evidenced thereby. Prior to 2013, the Quarterly Distribution Amount is
equal to the excess, if any, of (i) the cash that the Trust receives on or before the tenth day of the third month after the end of each calendar quarter ending before the Trust is dissolved
and that is attributable to production from the Net Profits Interest held by the Trust during that calendar quarter, plus, with certain exceptions, any other cash receipts of the Trust during such
quarter, over (ii) the liabilities for the Trust paid during such quarter, subject to adjustments for changes made by the Trustee during such quarter in any cash reserves established for the
payment of contingent or future obligations of the Trust. Based on the payment procedures relating to the Net Profits Interests, cash received by the Trustee in a particular quarter from the Net
Profits Interests reflects 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. Prior to 2013, the Quarterly Distribution Amount for each quarter is payable to Unitholders of record on the Quarterly Record Date, which is the last day of the second month
following the end of such calendar quarter or such later date as the Trustee determines is required to comply with legal or stock exchange requirements. In accordance with the procedures set forth in
the Trust Agreement relating to the pending liquidation of the Trust, no further distributions relating to the Net Profits Interests will be made until a final distribution is made in connection with
the liquidation of the Trust.
The
net taxable income of the Trust for each calendar quarter is reported by the Trustee for tax purposes as belonging to the holders of record to whom the Quarterly Distribution Amount
was or will be distributed. Assuming that the Trust will be classified for tax purposes as a "grantor trust," the net taxable income will be realized by the holders for tax purposes in the calendar
quarter received by the Trustee, rather than in the quarter distributed by the Trustee. Taxable income of a holder may differ from the Quarterly Distribution Amount because the Treasury Obligations
will be treated as generating interest income for tax purposes. There may also be minor variances because of the possibility that, for example, a reserve will be established in one quarter that will
not give rise to a tax deduction until a subsequent quarter, an expenditure paid for in one quarter will have to be amortized for tax purposes over several quarters.
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Possible Divestiture of Depositary Units and Trust Units
The Trust Agreement imposes no restrictions based on nationality or other status of holders of Trust Units. However, the Trust
Agreement and the Deposit Agreement provide that in the event of certain judicial or administrative proceedings seeking the cancellation or forfeiture of any property in which the Trust has an
interest because of the nationality, citizenship, or any other status, of any one or more holders of Trust Units including holders of Depositary Units, the Trustee will give written notice thereof to
each holder whose nationality, citizenship or other status is an issue in the proceeding, which notice will constitute a demand that such holder dispose of his Depositary Units or withdrawn Trust
Units within 30 days. If any holder fails to dispose of his Depositary Units or withdrawn Trust Units in accordance with such notice, cash distributions on such units are subject to suspension.
In the event a holder fails to dispose of Depositary Units in accordance with such notice, the Depositary may cancel such holder's Depositary Units and reissue them in the name of the Trustee,
whereupon the Trustee will use its reasonable efforts to sell the Depositary Units and remit the net sale proceeds to such holder. In the case of Trust Units withdrawn from deposit with the
Depositary, the Trustee shall redeem such Trust Units not divested in accordance with such notice, for a cash price equal to the then-current market price of the Depositary Units less the
then-current over-the-counter bid price of the related, withdrawn Treasury Obligations. The redemption price will be paid out in quarterly installments limited to
the amount that otherwise would have been distributed in respect of such redeemed Trust Units.
Liability of Unitholders
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 courts outside of Delaware would give effect to such limitation.
Liquidation of the Trust
The Trust will be liquidated and terminate during 2013.
On
August 16, 2012 the Trust entered into a Brokerage Agreement, pursuant to which the Trust engaged EnergyNet.com, Inc. ("EnergyNet") to perform sales brokerage and
consulting services in connection with the Trust's anticipated sale of the Royalty NPI. EnergyNet subsequently informed the Trustee that its marketing activities resulted in 190 companies reviewing
materials relating to the Royalty NPI, with approximately ten of the companies conducting more extensive reviews. EnergyNet then solicited bids for the Royalty NPI. In marketing the Royalty NPI, the
Trustee solicited bids on the basis of the distribution for the third quarter of 2012 being for the account of the Trust, and the distribution for the fourth quarter of 2012 being for the account of
the purchaser of the Royalty NPI.
Pursuant
to the Trust Agreement, ECA, which held a right of first refusal to purchase the Royalty NPI from the Trust, had the right to require the Trust to engage an appraiser to
appraise the Royalty NPI if the Trust had not sold the Royalty NPI by September 30, 2012. ECA also had the right to purchase the Royalty NPI at the appraised value. At the request of the
Trustee, on September 25, 2012, ECA granted a waiver in order to allow the Trust additional time in which to market the Royalty NPI. ECA further agreed to waive the 20-business day
notice of a proposed sale to which it was entitled under the Trust Agreement in order to allow the Trust additional time in which to market the Royalty NPI, and agreed to accept a shorter notice
period.
Bids
for the Royalty NPI were due in October 2012. The Trust accepted the highest bid, and entered into the October 24, 2012 Agreement described above. On November 5, 2012,
ECA exercised its right of first refusal under the Trust Agreement to purchase the Royalty NPI on the terms set forth in the October 24, 2012 Agreement. As a consequence of ECA's exercise of
its right of first refusal, the
19
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October 24,
2012 Agreement terminated in accordance with its terms, and the Trust became obligated to sell the Royalty NPI to ECA for the purchase price determined by the October 24,
2012 Agreement. On January 3, 2013, the Trust entered into a Purchase and Sale Agreement with ECA to document the terms of the sale of the Royalty NPI to ECA and to eliminate provisions of the
October 24, 2012 Agreement that were inapplicable to the sale of the Royalty NPI to ECA. The sale of the Royalty NPI to ECA was completed on January 10, 2013. The price, after making the
adjustment for gas price changes required by the October 24, 2012 Agreement, was $5,917,275, and was paid in cash. Expenses paid or to be paid in connection with the sale include the brokerage
fee of approximately $158,000.
Unitholders
as of the close of business on May 31, 2013 will, on or about June 17, 2013, as a result of the liquidation and winding down of the Trust beginning on
May 15, 2013, receive the proceeds attributable to the mature Treasury Obligation ($20.00 per trust unit), unless the Treasury Obligation relating thereto has previously been withdrawn. On or
about August 15, 2013, such Unitholders will also receive their pro rata share of the net proceeds received from the Trust's sale in January 2013 of the Royalty NPI (estimated to be
approximately $0.95 per trust unit, based on net proceeds of $5.65 million) plus their pro rata share of revenues attributable to the term net profits interest for the period beginning
October 1, 2012 through May 15, 2013, less any costs and expenses or reserves of the Trust during such period. Trading in the trust units will be stopped at the end of regular trading on
the NYSE at the close of business on May 31, 2013, and no transfers will be permitted after that date.
FEDERAL INCOME TAX MATTERS
The Trust is a grantor trust and therefore is not subject to federal income taxes. Accordingly, no recognition has been given to
federal income taxes in the Trust's financial statements. The Trust Unitholders are treated as the owners of Trust income and assets, and the entire federal taxable income of the Trust will be
reported by the Trust Unitholders on their respective tax returns.
Widely Held Fixed Investment Trust Reporting Information
The Trustee assumes that some Depositary units and the underlying Trust Units are held by middlemen, as such term is broadly defined in
U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as "middlemen").
Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust ("WHFIT") for U.S. Federal
income tax purposes. Accordingly, the Trust will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a
WHFIT. The representative of the Trust that will provide the required information is The Bank of New York Mellon Trust Company, N.A., and the contact information for the representative is as follows:
The
Bank of New York Mellon Trust Company, N.A., Trustee
Global Corporate Trust
919 Congress Ave., Suite 500
Austin, Texas 78701
Telephone: 1-800-852-1422
Available Trust Tax Information
In compliance with the reporting requirements for WHFITs and the dissemination of trust tax reporting information, the trustee provides
a generic tax information reporting booklet that is intended to be used only to assist unitholders in the preparation of their 2012 federal and state income tax returns. This tax information booklet
can be obtained at http://ngt.investorhq.businesswire.com.
Notwithstanding
the foregoing, the middlemen holding the Depositary Units and the underlying Trust Units on behalf of Unitholders, and not the Trustee of the Trust, are solely
responsible for
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complying
with the information reporting requirements under the Treasury Regulations with respect to such Depositary Units and the underlying Trust Units, including the issuance of IRS
Forms 1099 and certain written tax information statements to the investor.
Each
Unitholder should consult his or her own tax advisor regarding Trust tax compliance matters.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting
individual Unitholders. Unitholders are urged to consult their own legal and tax advisors with respect to these matters.
The
Trust owns the Net Profits Interests burdening the Underlying Properties located in the states of Pennsylvania and West Virginia. Both of these states have income taxes applicable to
individuals and may require the Trust to withhold taxes from distributions made to nonresident Unitholders. Withholding, if required, is at the rate of 6.5% of taxable income attributable to West
Virginia and 3.07% of taxable income attributable to Pennsylvania. A Unitholder may be required to file state income tax returns and/or to pay taxes in these states and may be subject to penalties for
failure to comply with such requirements. Generally, Unitholders may treat state income taxes that the Trust has withheld as having been paid by them to the state for which they were withheld.
Unitholders may be able to treat any taxes that they have paid or that have been withheld and paid to West Virginia or Pennsylvania as a deduction in computing Federal income tax, or as a credit or a
deduction in computing another state's income tax.
Unitholders
receive information concerning the Depositary Units and the Trust Units sufficient to identify the income from Depositary Units that is allocable to each state. Holders of
Depositary Units should consult their own tax advisors to determine their income tax filing requirements with respect to their share of income of the Trust allocable to states imposing a tax on such
income.
The
Trust Units and therefore also the Depositary Units may constitute real property or an interest in real property under the tax, inheritance, estate and probate laws of either or both
of Pennsylvania and West Virginia. If the Depositary Units are held to be real property or an interest in real property under the laws of a state in which the Underlying Properties are located, the
holders of Depositary Units may be subject to ad valorem or other property tax, devolution, probate and administration laws, and inheritance or estate and similar taxes, under the laws of such state.
Available Information
The Trust makes copies of its reports under the Exchange Act available at
www.businesswire.com/cnn/ngt.htm
. The Trust's filings under the
Exchange Act are also available electronically from the website maintained by the
Securities and Exchange Commission at http://www.sec.gov. The Trust will also provide electronic and paper copies of its recent filings free of charge upon request to the Trustee.
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
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widely
in response to a number of factors that are beyond the control of ECA 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 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 ECA. As operator, ECA 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.
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Compliance with governmental regulations 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. Increases in chargeable costs have the effect of reducing the amount of
Net Proceeds.
Administrative costs reduce distributions to Unitholders.
Administrative costs, including the Trustee's fee and other professional services fees and expenses, are deducted prior to
distributions to Unitholders. Such costs could fluctuate in 2013 depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering
services, and may be materially higher during 2013 than they have been in the past as the Trust incurs expenses in connection with its liquidation in accordance with the Trust Agreement.
Administrative costs adversely affect distributions to Unitholders.
The legal status of the Net Profits Interests under some circumstances is unclear.
At the time of the formation of the Trust, ECA 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, ECA recorded the Conveyances in the real property records of West Virginia and Pennsylvania in accordance with local
recording acts. ECA believes that, if, during the term of the Trust, ECA 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 ECA. 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, ECA 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 ECA's rights to the Underlying Properties.
The Net Profits Interests are subject to any defects in ECA's rights with respect to the Underlying Properties. ECA 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, ECA 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
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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.
ECA and the Trust may have conflicts of interest.
The interests of ECA and the interests of the Trust and the Unitholders may at times be different. For example, ECA'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, ECA 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, and now with
ECA as successor by merger, or ECA under the Gas Purchase Contract. In addition, ECA 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 ECA from drilling additional wells on the same property as the wells subject to the Net Profits Interests provided that ECA
complies with both of these covenants. In addition, these covenants would not prohibit ECA from drilling development wells on adjacent properties provided that ECA complies with the 1,000 foot
limitation. If ECA 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 ECA, and do not apply to third parties.
In
addition, ECA's interests may conflict with those of the Trust and the Unitholders in situations involving the sale of Underlying Properties. ECA has the right to sell all or any
portion of the Underlying Properties without restrictions; however, except in limited circumstances where ECA 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 ECA. ECA 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
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for
profit. No assurance can be given, however, that the courts in jurisdictions outside of Delaware would give effect to such limitation.
There are risks associated with the financial position of ECA.
ECA 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 ECA, as successor to Eastern Marketing, to perform its obligations under the Gas Purchase Contract depends on its 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 ECA.
The tax treatment of an investment in Trust Units or Depositary Units could be affected by recent and potential legislative changes, possibly on a retroactive basis.
The Health Care and Education Affordability Reconciliation Act of 2010 includes a provision that, in taxable years beginning after
December 31, 2012, subjects an individual having modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to a "Medicare tax" equal
generally to 3.8% of the lesser of such excess or the individual's net investment income, which appears to include royalty income and interest income, if any, derived from the Trust Units or
Depositary Units as well as any net gain from the disposition of Trust Units or Depositary Units. In addition, beginning January 1, 2013, the highest marginal U.S. federal income tax rate
applicable to ordinary income and long-term capital gains of individuals increased to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any
time.