As filed with the Securities and Exchange Commission on May 7, 2010

Registration No. 333-165833

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933


ECA Marcellus Trust I (Exact name of co-registrant as specified in its charter)		Energy Corporation of America (Exact name of co-registrant as specified in its charter)
Delaware (State or other jurisdiction of incorporation or organization)		West Virginia (State or other jurisdiction of incorporation or organization)
1311 (Primary Standard Industrial Classification Code Number)		1311 (Primary Standard Industrial Classification Code Number)
27-6522024 (I.R.S. Employer Identification No.)		84-1235822 (I.R.S. Employer Identification No.)
919 Congress Avenue Suite 500 Austin, Texas 78701 (512) 236-6599		4643 South Ulster Street Suite 1100 Denver, Colorado 80237 (303) 694-2667
(Address, including zip code, and telephone number, including area code, of agent of service)		(Address, including zip code, and telephone number, including area code, of agent of service)
The Bank of New York Mellon Trust Company, N.A. 919 Congress Avenue Suite 500 Austin, Texas 78701 (512) 236-6599 Attention: Michael J. Ulrich		Donald C. Supcoe 4643 South Ulster Street Suite 1100 Denver, Colorado 80237 (303) 694-2667
(Name, address, including zip code, and telephone number, including area code, of agent for service)		(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this Registration Statement becomes effective.

Copies to:


David P. Oelman Vinson & Elkins L.L.P. First City Tower 1001 Fannin Street, Suite 2500 Houston, Texas 77002-6760 (713) 758-2222		Thomas R. Goodwin Tammy J. Owen Goodwin & Goodwin, LLP 300 Summers Street Suite 1500 Charleston, West Virginia 25301 (304) 346-7000		Joshua Davidson Baker Botts L.L.P. One Shell Plaza 910 Louisiana St. Houston, Texas 77002 (713) 229-1234

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

The Registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrants shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act, or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission (or the “SEC”), acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities, and we are not soliciting an offer to buy these securities, in any jurisdiction where the offer or sale is not permitted.

Subject to Completion dated May 7, 2010

PRELIMINARY PROSPECTUS

ECA Marcellus Trust I

9,000,000 Common Units

This is an initial public offering of common units representing beneficial interests in ECA Marcellus Trust I. The trust is selling all of the units offered hereby. Energy Corporation of America (“ECA”) has formed the trust and will convey, or cause to be conveyed, certain royalty interests and certain hedging contracts established for the benefit of the trust in exchange for all of the net proceeds of this offering as well as common and subordinated units representing a 50% beneficial interest in the trust.

Prior to this offering, there has been no public market for the common units. ECA expects that the public offering price will be between $ and $ per common unit. The trust has been approved to apply for the listing of its common units on the New York Stock Exchange under the symbol “ECT.”

The Trust Units. Trust units, consisting of the common and subordinated units, are units of beneficial interest in the trust and represent undivided interests in the trust. They do not represent any interest in ECA.

The Trust. The trust will own term and perpetual royalty interests in natural gas properties owned by ECA in the Marcellus Shale formation in Greene County, Pennsylvania. These royalty interests will entitle the trust to receive 90% of the proceeds attributable to ECA’s interest in the sale of production from 14 producing horizontal Marcellus Shale natural gas wells located in Greene County, Pennsylvania and 50% of the proceeds attributable to ECA’s interest in the sale of production from 52 horizontal Marcellus Shale natural gas development wells to be drilled on drill sites included within approximately 9,300 net acres held by ECA in Greene County, Pennsylvania. The trust will be treated as a partnership for federal income tax purposes.

The Trust Unitholders. As a trust unitholder, you will receive quarterly distributions of cash from the proceeds that the trust receives from ECA’s sale of natural gas subject to the royalty interests held by the trust.

Ownership of Trust Units by ECA. After the completion of this offering, ECA will own 3,395,433 common units and 4,500,000 subordinated units representing 43.9% of trust units. If the underwriters exercise their over-allotment option in full, ECA will own 2,045,433 common units and 4,500,000 subordinated units representing 36.4% of trust units. Certain Private Investors will own 1,104,567 common units representing 6.1% of trust units. For more information on the Private Investors, please read “Certain Transactions.”

ECA’s Right to Incentive Distributions. ECA will be entitled to receive incentive distributions equal to 50% of the amount, if any, by which the cash available for distribution on all of the trust units in any quarter exceeds certain target distribution levels. ECA will be entitled to reimbursement for $5 million in expenses incurred in connection with establishing floor price contracts to be transferred to the trust from the remaining 50% of cash available for distribution in excess of these thresholds. Please see “Target Distributions and Subordination and Incentive Thresholds.”

Investing in the common units involves a high degree of risk. Before buying any common units, you should read the discussion of material risks of investing in the common units in “Risk factors” beginning on page 17 of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Common Unit	Total

Price to the public	$	$
Underwriting discounts and commissions	$	$
Proceeds to the trust (before expenses)	$	$

The underwriters may also purchase up to an additional 1,350,000 common units at the initial public offering price, less underwriting discounts and commissions, to cover over-allotments, if any, within 30 days of the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $ , and the trust’s total proceeds, after deducting underwriting discounts and commissions and before expenses, will be $ . The net proceeds of any exercise of the underwriters’ over-allotment option will be used to redeem an equal number of common units held by ECA.

The underwriters are offering the common units as set forth under “Underwriting.” Delivery of the common units will be made on or about , 2010.


RAYMOND JAMES	CITI

, 2010

TABLE OF CONTENTS


Summary			1
Risk factors			17
Forward-looking statements			39
Use of proceeds			40
Natural gas fundamentals in the Marcellus Shale			41
Energy Corporation of America			44
The trust			53
Target distributions and subordination and incentive thresholds			56
The underlying properties			65
Description of the royalty interests			79
Description of the trust agreement			84
Description of the trust units			90
Trust units eligible for future sale			93
Federal income tax considerations			95
State tax considerations			114
ERISA considerations			115
Selling trust unitholder			116
Underwriting			117
Certain transactions			122
Legal matters			125
Experts			125
Where you can find more information			125
Glossary of certain oil and natural gas terms and terms related to the trust			126
Index to financial statements			F-1
Information about Energy Corporation of America			ECA-1
Summary reserve reports			A-1
Calculation of target distributions			B-1
EX-4.2
EX-23.1

Important Notice About Information in This Prospectus

You should rely only on the information contained in this prospectus. Until , 2010 (25 days after the date of this prospectus), federal securities laws may require all dealers that effect transactions in the common units, whether or not participating in this offering, to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

ECA and the trust have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the common units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The trust’s business, financial condition, results of operations and prospects may have changed since such dates or in any free writing prospectus we may authorize to be delivered to you.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors and the financial statements and notes to those statements. Definitions for terms relating to the natural gas business can be found in “Glossary of certain oil and natural gas terms and terms related to the trust.” Ryder Scott Company, L.P., an independent engineering firm, provided the estimates of proved natural gas reserves as of March 31, 2010 included in this prospectus. These estimates are contained in a summary prepared by Ryder Scott of its reserve report as of March 31, 2010 for the Underlying Properties held by ECA described below and for the royalty interests in the Underlying Properties held by the trust, which royalty interests are referred to herein as the “trust properties.” This summary is located at the back of this prospectus as Annex A and is referred to in this prospectus as the “reserve report.” References to “Energy Corporation of America” or “ECA” in this prospectus are to Energy Corporation of America and its subsidiaries and, when discussing unit ownership and historical ownership of the royalty interests, includes the private investors listed in “Certain Transactions” (such private investors being referred to herein as the “Private Investors”). Unless otherwise indicated, all information in this prospectus assumes an initial public offering price of $ per common unit and no exercise of the underwriters’ over-allotment option.

ECA Marcellus Trust I

ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation of America to own royalty interests in 14 producing horizontal natural gas wells producing from the Marcellus Shale formation and located in Greene County, Pennsylvania (the “Producing Wells”) and royalty interests in 52 horizontal natural gas development wells to be drilled to the Marcellus Shale formation (the “PUD Wells”) within the “Area of Mutual Interest,” or “AMI”, comprised of 9,300 net acres held by ECA in Greene County, Pennsylvania. The royalty interests will be conveyed from ECA’s working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation (the “Underlying Properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the trust to receive 90% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest”) entitles the trust to receive 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells. Approximately 50% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged with a combination of floors and swaps from April 1, 2010 to March 31, 2014. The floor price contracts will be transferred to the trust by ECA, while ECA will enter into back-to-back swap agreements with the trust to provide the trust with the benefit of swap contracts entered into between ECA and third parties. ECA will be entitled to recoup the costs of establishing the floor price contracts only if and to the extent cash available for distribution by the trust exceeds certain levels. Please see “Target Distributions and Subordination and Incentive Thresholds.”

ECA is obligated to use commercially reasonable efforts to drill all of the PUD Wells by March 31, 2013. In the event of delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA will grant to the trust a lien on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which are already producing and not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells (the “Drilling Support Lien”). The amount obtained by the trust pursuant to the Drilling Support Lien may not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the completed PUD Wells will be released from the lien.

The trust will not be responsible for any costs related to the drilling of development wells or any other development or operating costs. The trust’s cash receipts in respect of the royalties will be determined after deducting post-production costs and any applicable taxes associated with the PDP and PUD Royalty Interests, and the trust’s cash available for distribution will include cash receipts from its hedging contracts and will be reduced by trust administrative expenses and expenses incurred as a result of being a publicly traded entity. Post-production costs will generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu gathered until ECA has fulfilled its drilling obligation (the “Post-Production Services Fee”); thereafter, ECA may increase the Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the Greene County Gathering System.

As of March 31, 2010 and after giving effect to the conveyance of the PDP Royalty Interest and the PUD Royalty Interest, the total gas reserves estimated to be attributable to the trust interests were 104.6 Bcf. This amount includes 72.4 Bcf attributable to the PUD Royalty Interest and 32.2 Bcf attributable to the PDP Royalty Interest.

ECA’s retained interest in the Underlying Properties entitles it to 10% of the proceeds from the sale of natural gas from the Producing Wells as well as 50% of the proceeds from the sale of future production from the PUD Wells. After giving effect to the trust’s royalty interests that burden ECA’s working interests in the Underlying Properties and taking into account the ownership by ECA of 43% of the trust units, ECA and its affiliates will retain an approximate 66% average economic interest in the Underlying Properties. ECA on average owns an 81.78% net revenue interest in the Producing Wells. Please read “Description of the Royalty Interests” below. ECA operates all of the Producing Wells and will agree to operate not less than 90% of the PUD Wells during the subordination period as defined below. In addition, ECA has agreed to operate the gas properties to which the PDP Royalty Interest and the PUD Royalty Interest relate and to cause to be marketed natural gas produced from these properties in the same manner it would if such properties were not burdened by the trust’s royalty interests.

The trust will make quarterly cash distributions of substantially all of its cash receipts, after deducting trust administrative expenses and the costs incurred as a result of being a publicly traded entity, on or about 60 days following the completion of each quarter through (and including) the quarter ending March 31, 2030 (the “Termination Date”). The first quarterly distribution is expected to be made on or about August 31, 2010 to record unitholders as of August 15, 2010. The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. At the Termination Date, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds therefrom will be distributed pro rata to the unitholders soon after the Termination Date. ECA will have a first right of refusal to purchase the remaining 50% of the royalty interests at the Termination Date. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of your original investment.

The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A. as trustee. Although ECA will operate all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the trust.

TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS

Subordination and Incentive Thresholds

ECA has calculated quarterly target levels of cash distributions for the life of the trust as set forth on Annex B to this prospectus. The amount of the quarterly distributions may fluctuate from quarter to quarter, depending on the proceeds received by the trust, among other factors. Annex B reflects that while target distributions increase as ECA completes its drilling obligations and production attributable to the trust increases, over time these target distributions decline as a result of the depletion of the reserves in the Underlying Properties. These “target distributions” do not represent the actual distributions you should expect to receive with respect to your common units. Rather, the trust has established the target distributions in part to calculate the subordination and incentive thresholds described in more detail below. The target distributions were derived by assuming that natural gas production from the trust properties will equal the volumes reflected in the reserve report attached as Annex A to this prospectus and the prices received for such production will equal NYMEX forward pricing as of March 11, 2010 for the thirty-six month period ending March 31, 2013 and increased thereafter by a 2.5% annual escalator (as adjusted for a basis differential of $0.15 per MMBtu), capped at $9.00 per MMBtu. Using these assumptions, the price per MMBtu would reach the $9.00 per MMBtu cap starting in 2025. The target distributions also give effect to post-production expenses projected in the reserve reports and projected trust administrative expenses, including the expenses incurred as a result of being a publicly traded entity. For more information on subordination and incentive thresholds, please read “— Target Distributions” below.

In order to provide support for cash distributions on the common units, ECA has agreed to subordinate 4,500,000 of the trust units it will retain following this offering, which will constitute 25% of the outstanding trust units. While the subordinated units will be entitled to receive pro rata distributions from the trust if and to the extent there is sufficient cash to provide a cash distribution on the common units which is no less than the applicable quarterly subordination threshold, if there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Each applicable quarterly subordination threshold is equal to 80% of the target distribution level for the corresponding quarter as reflected on Annex B (each, a “subordination threshold”). In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, ECA will be entitled to receive incentive distributions (the “incentive distributions”) equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 150% of the subordination threshold for such quarter (which is 120% of the target distribution for such quarter) (each, an “incentive threshold”). ECA’s right to receive this incentive distribution will terminate upon the expiration of the subordination period.

ECA has incurred costs of approximately $5 million in establishing the floor price contracts being transferred to the trust. ECA will be entitled to reimbursement for these expenditures only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the trust unitholders. ECA’s right to receive the remaining 50% of such cash in the form of incentive distributions would not be affected.

The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will

terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the floor price contracts to be transferred to the trust. The trust currently expects that ECA will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units will convert into common units on or before March 31, 2014. In the event of delays, ECA will have until March 31, 2014 to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015. The period during which the subordinated units are outstanding is referred to as the “subordination period.”

The table below sets forth the target distributions and subordination and incentive thresholds for each calendar quarter during the full potential subordination period. The effective date of the trust is April 1, 2010, meaning it will receive the proceeds of production attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest will not be conveyed to the trust until the closing of this offering.


	Subordination		Target		Incentive
Period	Threshold		Distribution		Threshold
			(per unit)

2010:
Second Quarter	$	0.217	$	0.271	$	0.326
Third Quarter		0.298		0.372		0.447
Fourth Quarter		0.426		0.532		0.639
2011:
First Quarter		0.413		0.516		0.619
Second Quarter		0.418		0.523		0.627
Third Quarter		0.520		0.650		0.780
Fourth Quarter		0.544		0.680		0.815
2012:
First Quarter		0.562		0.702		0.843
Second Quarter		0.595		0.744		0.893
Third Quarter		0.607		0.759		0.911
Fourth Quarter		0.688		0.859		1.031
2013:
First Quarter	$	0.773	$	0.967	$	1.160
Second Quarter		0.771		0.964		1.157
Third Quarter		0.717		0.896		1.075
Fourth Quarter		0.674		0.842		1.010
2014:
First Quarter		0.623		0.779		0.935
Second Quarter		0.601		0.751		0.902
Third Quarter		0.583		0.728		0.874
Fourth Quarter		0.561		0.701		0.841
2015:
First Quarter		0.530		0.663		0.795

For additional information with respect to the subordination and incentive thresholds, please see “Target Distributions and Subordination and Incentive Thresholds” and “Description of the Royalty Interests.”

Target Distributions

The table below presents the calculation of the target distributions for each quarter through and including the quarter ending June 30, 2011. The target distributions were prepared by ECA on an accrual basis based on production volumes, pricing and other assumptions. As used herein, accrual basis means ECA will pay to the trust each quarter an amount equal to the estimated proceeds of production from the trust properties during the calendar quarter most recently ended before the distribution (after deducting post-production costs and any applicable taxes), regardless of whether such amounts have actually been received by ECA from the purchaser of the natural gas produced. Any difference between the payment made by ECA to the trust with respect to a calendar quarter and the actual cash production payments relative to the trust properties received by ECA will be netted against future payments by ECA to the trust. Actual cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of natural gas produced from the Underlying Properties, the prices received for natural gas production and other factors. Please read “Target Distributions and Subordination and Incentive Thresholds — Significant Assumptions Used to Prepare the Target Distributions.”

ECA does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of ECA has prepared the projected operational and financial information set forth below in order to present the target distributions attributable to the natural gas sales volumes reflected in Ryder Scott’s reserve report attached hereto as Annex A.


	Quarters Ending
	June 30,			September 30,			December 31,			March 31,			June 30,
	2010			2010			2010			2011			2011
	(In thousands, except well number, volumetric and per unit data)

Number of wells producing at quarter end		8			17			22			25			31
*Estimated Production from Trust Properties*
Natural Gas PDP Sales Volumes (MMcf)		879			1,190			1,265			1,066			962
Natural Gas PUD Sales Volumes (MMcf)		—			81			514			553			769
Total Sales Volumes (MMcf)		879			1,271			1,779			1,619			1,731
Daily Sales Volumes (Mcf/d)		9,664			13,814			19,336			17,988			19,020
*Commodity Prices and Hedging Positions (1)*
Assumed NYMEX Price ($/MMBtu) (2)	$	4.58		$	4.75		$	5.27		$	5.81		$	5.34
Assumed Price ($/Mcf) (2)		4.72			4.89			5.42			5.98			5.50
Realized Unhedged Price after Basis Differential ($/Mcf)		4.88			5.04			5.58			6.13			5.65
Daily Hedged Volumes (MMcf/d) (3)		7.3			7.3			9.7			9.0			9.5
Percent of Total Volumes Swapped		75	%		53	%		38	%		40	%		38	%
Swap Price ($/MMBtu)	$	6.75		$	6.75		$	6.75		$	6.75		$	6.75
Percent of Total Volumes Floored		—			—			12	%		10	%		12	%


	Quarters Ending
	June 30,		September 30,		December 31,		March 31,		June 30,
	2010		2010		2010		2011		2011
	(In thousands, except well number, volumetric and per unit data)

Floor Price ($/MMBtu)	$	—	$	—	$	5.00	$	5.00	$	5.00
Realized Hedged Weighted Average Price ($/Mcf) (3)	$	6.55	$	6.13	$	6.15	$	6.53	$	6.21
*Cash available for distribution*
Gas Sales Revenues	$	4,288	$	6,408	$	9,923	$	9,932	$	9,786
Swap and Floor Hedge Revenues		1,476		1,381		1,021		635		960

Total Revenues	$	5,764	$	7,788	$	10,944	$	10,566	$	10,746

Post-Production Services Fee (4)	$	471	$	681	$	953	$	867	$	927
Trust Expenses		200		200		200		200		201
Franchise Taxes		207		207		211		211		211

Cash Available for Distribution	$	4,885	$	6,701	$	9,581	$	9,288	$	9,407

Trust Units Outstanding		18,000		18,000		18,000		18,000		18,000
Target Distribution Per Trust Unit	$	0.271	$	0.372	$	0.532	$	0.516	$	0.523
Subordination Threshold Per Trust Unit	$	0.217	$	0.298	$	0.426	$	0.413	$	0.418
Incentive Threshold Per Trust Unit	$	0.326	$	0.447	$	0.639	$	0.619	$	0.627


(1)		For a more detailed description of the natural gas hedging contracts established for the benefit of the trust, please see “Description of the Royalty Interests.”

(2)		Based on NYMEX forward pricing as of March 11, 2010. Assumed price per Mcf calculated based on an assumed conversion rate of 1.03 MMBtu per Mcf.

(3)		Adjusted for an assumed basis differential of $0.15 per MMBtu.

(4)		Consists of a fee of $0.52 per MMBtu.

ENERGY CORPORATION OF AMERICA

ECA is a privately held energy company engaged in the exploration, development, production, gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and ECA is one of the largest natural gas operators in the Appalachian Basin. As of December 31, 2009, ECA operated approximately 5,100 wells in the Appalachian Basin and had an aggregate net leasehold position of approximately one million acres, with 85% of this acreage held by production. ECA sells gas from its own wells as well as third-party wells to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. ECA owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities. During the fiscal year ended June 30, 2009, ECA aggregated and sold 22.5 Bcf of gas for an average of 62 MMcf of gas per day, of which 20.7 Bcf, or 57 MMcf per day, represented sales of gas produced from wells operated by ECA.

ECA was formed in September 1992 as a Colorado corporation and subsequently reincorporated in West Virginia through a merger with ECA’s predecessor in June 1995. ECA’s predecessor began operating in the Appalachian Basin in 1963. ECA’s principal offices are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and its telephone number is (303) 694-2667. For additional information concerning ECA, see “Information about Energy Corporation of America” beginning on page ECA-1 of this prospectus. ECA will be required to deliver to the trustee a statement of the computation of the proceeds for each computation period, as well as quarterly drilling and production results. ECA will not be a reporting company following this offering and will not file periodic reports with the SEC. Therefore, as a trust unitholder, you will not have access to financial information of ECA.

The trust units do not represent interests in or obligations of ECA.

FORMATION TRANSACTIONS

At or prior to the closing of this offering, the following transactions, which are referred to as the “formation transactions,” will occur:


	•	ECA will convey to a wholly owned subsidiary a term royalty interest entitling the holder of the interest to receive 45% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PDP Royalty”) and a term royalty interest entitling such holder of the interest to receive 25% of the proceeds from the sale of the production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PUD Royalty”) in exchange for a demand note in the principal amount of $ million. The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the “Term Royalties.”

	•	ECA and the Private Investors will convey to the trust perpetual royalty interests entitling the trust to receive, in the aggregate, 45% of the proceeds from the sale of production of natural gas attributable to the interests of ECA in the Producing Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PDP Royalty”) and ECA will convey to the trust a perpetual royalty interest entitling the trust to receive an additional 25% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PUD Royalty”) in exchange for, in the case of ECA, 3,186,117 common units constituting 17.7% of the trust units outstanding and 4,500,000 subordinated units constituting 25% of the trust units outstanding and, in the case of the Private Investors, 1,313,883 common units constituting 7.3% of the trust units outstanding. The Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the “Perpetual Royalties.”

	•	The trust will sell the 9,000,000 common units offered hereby to the public, representing a 50% interest in the trust.


	•	ECA will convey to the trust the natural gas floor price contracts and will enter into the back-to-back swap agreements with the trust to provide the trust with the benefit of the swap contracts entered into between ECA and third parties.


	•	ECA’s subsidiary will convey the Term Royalties to the trust in exchange for a distribution from the net proceeds of this offering and will use the net proceeds to repay the demand note to ECA.


	•	ECA will purchase 209,316 common units from the Private Investors at the initial offering price.

	•	ECA and the trust will enter into an Administrative and Drilling Services Agreement outlining the provision of administrative services to the trust and its compensation therefor and ECA’s drilling obligation to the trust with respect to the PUD Wells. Please see “The Trust — Administrative and Drilling Services Agreement.”


	•	ECA will grant to the trust the Drilling Support Lien.


	•	ECA will grant to the trust a lien on the PDP Royalty Interest and the PUD Royalty Interest (the “Royalty Interest Lien”) to provide protection to the trust, in the event of a bankruptcy of ECA, against the risk that the PDP Royalty Interest or PUD Royalty Interest were not considered a real property interest.

STRUCTURE OF THE TRUST

The following chart shows the relationship of ECA, the trust and the public unitholders.

KEY INVESTMENT CONSIDERATIONS

The following are some key investment considerations related to the Underlying Properties, the royalty interests, and the common units:


	•	Royalty interests not burdened by operating or capital costs. The trust will not be responsible for any operating or capital costs associated with the Underlying Properties, including the costs to drill the PUD Wells. As a result, the trust’s burden to pay costs associated with any particular well will not arise until such well is producing natural gas attributable to the trust’s interest. The principal costs the trust will bear are the Post-Production Services Fee; property, ad valorem, production, severance, excise,

franchise and similar taxes, if any; and trust administrative expenses including costs incurred as a result of being a publicly traded entity. In addition, the trust will be obligated to reimburse ECA for approximately $5 million incurred in establishing the floor price contracts transferred to the trust if and to the extent cash available for distribution by the trust exceeds certain levels.


	•	Downside protection against natural gas price volatility through natural gas hedging contracts for approximately 50% of estimated production through March 31, 2014. ECA has established for the benefit of the trust certain floor price and swap hedging contracts covering approximately 50% of the expected production volumes attributable to the trust from April 1, 2010 through March 31, 2014. The swap contracts will relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period from April 1, 2010 through June 2012. The price of the floor price hedging contracts will be $5.00 per MMBtu. These hedging contracts should reduce commodity price risks inherent in holding interests in natural gas through the end of March 31, 2014.


	•	Alignment of interests between ECA and the trust unitholders. ECA is significantly incentivized to complete its drilling obligation, to increase production from the Underlying Properties and to obtain the best prices for the natural gas production from the Underlying Properties as a result of the following factors:


	-	ECA will retain an approximate average of 66% total economic interest in the Underlying Properties through its retained interest in the Underlying Properties and its ownership of approximately 43% of the trust units.

	-	A portion of the trust units that ECA will own, constituting 25% of the outstanding trust units, will be subordinated units that will not be entitled to receive distributions unless there is sufficient cash to pay the subordination threshold to the common units. These subordinated units will only convert into common units upon completion of the subordination period.


	-	To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period, ECA will be entitled to receive 50% of such cash as incentive distributions and 50% of such cash as recoupment of its costs for establishing the floor price contracts until it has recouped approximately $5 million.


	-	ECA will not be permitted to drill and complete any development wells in the Marcellus Shale formation on the lease acreage within the AMI for its own account or sell the Underlying Properties until it has satisfied its drilling obligation.


	•	Potential for initial depletion to be offset by results of development drilling. ECA is obligated to drill the PUD Wells by March 31, 2014. Furthermore, ECA is incentivized to increase production in the near term in order to receive incentive distributions. While production from the trust properties will decline in the long term, production from the PUD Wells will offset depletion of the Producing Wells in the near term.

	•	ECA’s experience and position as Marcellus Shale operator. Since January 1, 2006, ECA has drilled over 160 Marcellus Shale wells throughout the Appalachian Basin and operates Marcellus Shale wells in New York, Pennsylvania and West Virginia. ECA was one of the earliest operators in the Marcellus Shale region, having drilled test wells in this play in the late 1970s in partnership with the U.S. Department of Energy, and on


		April 18, 2008, it drilled and completed the Consol USX-13 well, which was one of the first horizontal Marcellus Shale wells in Greene County, Pennsylvania. ECA has drilled 141 gross vertical development wells and 21 gross horizontal wells in the Marcellus Shale formation, and it has successfully completed 100% of these wells. ECA is currently the operator of all of the Producing Wells and will agree to operate not less than 90% of the PUD Wells during the subordination period, allowing ECA to control the timing and amount of discretionary expenditures for operational and development activities with respect to substantially all of the PUD Wells. ECA’s senior managers possess an average of 27.5 years of industry experience with an extensive focus on operations in the Appalachian Basin and Marcellus Shale.


	•	ECA’s prior experience sponsoring a royalty trust. In 1993, ECA sponsored the formation of the Eastern American Natural Gas Trust (NYSE: NGT), a publicly traded Delaware trust (“NGT”), to which it contributed term net profits interests in Appalachian Basin natural gas properties. In connection with the formation of this trust, ECA agreed to drill 65 development wells over five years from which NGT would be entitled to a specified percentage of the proceeds from the natural gas production. ECA completed its obligation within the stipulated period. The historical results of operations and performance of NGT should not be relied on as an indicator of how the trust will perform.

In mid-2005, ECA entered into a term royalty transaction with a private investor. ECA conveyed to the private investor a 90% royalty interest in 312 producing gas wells located in the Appalachian Basin in West Virginia, Pennsylvania and Kentucky, as well as a 50% royalty interest in 180 development wells that were subsequently drilled by ECA in Kentucky and West Virginia. Although the parties originally contemplated that ECA would drill relatively shallow wells, 105 of the 180 development wells were completed to the deeper Marcellus Shale formation.


	•	Experience of ECA marketing natural gas production. As the operator of all of the Producing Wells and substantially all the PUD Wells, ECA will have the responsibility to market or cause to be marketed the natural gas production related to the Underlying Properties. During the fiscal year ended June 30, 2009, ECA and its affiliates aggregated and sold domestically an average of 62 MMcf of gas per day, of which 57 MMcf per day represented sales of natural gas produced from wells operated by ECA.

	•	Proximity of the Appalachian Basin to major markets. The Appalachian Basin is located close to a substantial number of large commercial and industrial gas markets, including natural gas powered electricity plants, and major residential markets in the northeastern United States. This proximity, together with the stable nature of Appalachian Basin production and the availability of transportation facilities, has resulted in generally higher realized prices for Appalachian Basin natural gas (including Marcellus Shale formation natural gas) than realized prices available in other regions of the United States.

The average realized sales prices for gas gathered and sold on ECA’s Greene County Gathering System (prior to any deduction for post-production costs) for each year in the three year period ended June 30, 2009 and the average NYMEX price for the same period are detailed in the table below:


	Average Greene County		Average NYMEX
Year	Gathering Price/MMBtu		Price/MMBtu

2007	$	7.17	$	6.86
2008		8.46		8.02
2009		6.85		6.39

During this three year period, ECA’s Greene County Gathering System received an average price that was $0.40 per MMBtu higher than the average NYMEX price for the same period. In establishing the subordination and incentive thresholds, ECA has assumed a basis differential of $0.15 per MMBtu.

KEY RISK FACTORS

Below is a summary of certain key risk factors for consideration related to the Underlying Properties, the royalty interests and the common units. This list is not exhaustive, please also read carefully the full discussion of these risks and other risks described under “Risk Factors” on page 17.


	•	Drilling and completion of PUD Wells on the Underlying Properties are high risk activities with many uncertainties that could delay ECA’s anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders.


	•	Natural gas prices fluctuate due to a number of factors that are beyond the control of the trust and ECA, and lower prices could reduce proceeds to the trust and cash distributions to unitholders.


	•	Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.


	•	Recently proposed severance taxes in Pennsylvania could, if enacted, materially increase the applicable taxes that are borne by the trust.


	•	The generation of proceeds for distribution by the trust depends in part on gathering, transportation and processing facilities owned by ECA and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.


	•	Due to the trust’s lack of industry and geographic diversification, adverse developments in the trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.


	•	The natural gas reserves estimated to be attributable to the Underlying Properties of the trust are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.


	•	The amount of cash available for distribution by the trust will be reduced by the amount of post-production costs, applicable taxes associated with the trust’s interest, trust expenses, incentive distributions and reimbursement obligations payable to ECA.


	•	The trust’s tax treatment depends on its status as a partnership for federal income tax purposes. If the IRS were to treat the trust as a corporation for federal income tax purposes, then its cash available for distribution to you would be substantially reduced.


	•	The ability of ECA to satisfy its obligations to the trust depends on the financial position of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in


		the event of ECA’s bankruptcy, it may be expensive and time-consuming for the trust to exercise its remedies.


	•	Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect ECA’s services.


	•	If the trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the trust’s cash available for distribution to you would be reduced.


	•	The trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the federal income tax positions the trust takes, the value of the trust units may be adversely affected, the cost of any IRS contest will reduce the trust’s cash available for distribution to you and income, gain, loss and deduction may be reallocated among trust unitholders.

PROVED RESERVES

Proved reserves of Underlying Properties and royalty interests. The following table, effective as of March 31, 2010, sets forth certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties, the PDP Royalty Interest and the PUD Royalty Interest, in each case derived from the reserve report. The reserve report was prepared by Ryder Scott in accordance with criteria established by the Securities and Exchange Commission, or “SEC.” In accordance with the SEC’s new rules, the reserves presented below were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from April 1, 2009 through March 1, 2010, without giving effect to the derivative transactions, and were held constant for the life of the properties. This yielded a price for natural gas of $3.984 per MMBtu. Proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property by the royalty interest assigned to the trust in each property. The net revenues attributable to the trust’s reserves are net of the trust’s obligation to reimburse ECA for post-production costs. The reserves related to the Underlying Properties include all proved reserves expected to be economically produced from the Marcellus Shale formation during the life of the properties. The reserves and revenues attributable to the trust’s interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period in which the trust owns the royalty interest as well as the 50% residual interest in the reserves that the trust will own on the Termination Date. A summary of the reserve report is included as Annex A to this prospectus.


	Proved Gas				Discounted
	Reserves		Estimated Future		Estimated Future
Proved Reserves	(Bcfe)		Net Revenues		Net Revenues (1)
	(Dollars in thousands)

Underlying Properties		193.8	$	507,289	$	168,687

Royalty Interests:
PDP Royalty Interest (90%) (2)		32.2	$	119,757	$	67,161
PUD Royalty Interest (50%)		72.4	$	269,175	$	133,109

Total		104.6	$	388,932	$	200,270


(1)		The present values of future net revenues for the Underlying Properties and the royalty interests were determined using a discount rate of 10% per annum.


(2)		Includes reserves currently behind pipe in existing wells which are in the process of being completed.

Annual production attributable to royalty interests. The following bar graph shows estimated annual production from the Underlying Properties attributable to the royalty interests based on the pricing and other assumptions set forth in the reserve report. The production estimates include the impact of additional production that is expected as a result of the drilling of the PUD Wells. The net production for 2010 only includes the nine months from April 1, 2010.

THE OFFERING


Common units offered to public		9,000,000 common units

		10,350,000 common units, if the underwriters exercise their over-allotment option in full

Trust units owned by ECA after the offering		3,395,433 common units and 4,500,000 subordinated units

		2,045,433 common units and 4,500,000 subordinated units, if the underwriters exercise their over-allotment option in full

Common units owned by the Private Investors		1,104,567 common units. For more information on the common units owned by the Private Investors, please read “Certain Transactions.”

Total units outstanding after the offering		13,500,000 common units and 4,500,000 subordinated units

Use of proceeds		The trust is offering the common units to be sold in this offering. Assuming no exercise of the underwriters’ over-allotment option and an initial public offering price of $ per common unit, the estimated net proceeds of this offering will be approximately $ million, after deducting underwriting discounts and commissions and offering expenses. The trust will use the net proceeds to pay a wholly-owned subsidiary of ECA for the conveyance of the Term Royalties. In turn, such subsidiary will use such amount to repay a $ million demand note payable to ECA to be issued as consideration for the transfer of the Term Royalties thereto.

		The trust will use the net proceeds from any exercise of the underwriters’ over-allotment option to repurchase an equal number of common units from ECA at the initial public offering price, after deducting underwriting discounts and commissions.


		ECA intends to use the proceeds received both from the repayment of the demand note by ECA’s subsidiary and from any exercise of the underwriters’ over-allotment option to purchase 209,316 common units from the Private Investors at the initial offering price, to reduce borrowings under its revolving credit facility and for general corporate purposes. Please read “Use of Proceeds.”


Proposed NYSE symbol		“ECT”


Trustee		The Bank of New York Mellon Trust Company, N.A.


Quarterly cash distributions		Actual cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of natural gas produced from the Underlying Properties, the prices received for natural gas production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties initially increasing and subsequently diminishing over time, a portion of each distribution will represent a return of your original investment and the target distributions will decline over time. Production declines are expected to be offset in the near term by production realized from the drilling and successful completion of the PUD Wells.

		It is expected that quarterly cash distributions during the term of the trust will be made by the trustee on or about the 60th day following the end of each calendar quarter to the trust unitholders of record on or about the 45th day following each calendar quarter. The first distribution from the trust to the trust unitholders will be made on or about August 31, 2010. The first distribution to the trust unitholders will be based upon amounts to be received from ECA for estimated production attributable to the royalty interests and proceeds attributable to the hedging contracts for the period commencing on April 1, 2010 and ending on June 30, 2010, regardless or whether such amounts have actually been received by ECA from the purchaser of the natural gas produced.

Termination of the trust		The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.

Summary of income tax considerations		The trust will be treated as a partnership for federal income tax purposes. Consequently, the trust will not incur any federal income tax liability. Instead, trust unitholders will be allocated an amount of the trust’s income, gain, loss, or deductions corresponding to their interest in the trust, which amounts may differ in timing or amount from actual distributions. The Term PDP Royalty will and the Term PUD Royalty should be treated as debt instruments for federal income tax purposes, and the trust will be required to treat a portion of each payment it receives with respect to each such royalty interest as interest income in accordance with the “noncontingent bond method” under the original issue discount rules contained in the Internal Revenue Code of 1986, as amended, and the corresponding


		regulations. The Perpetual PDP Royalty will and the Perpetual PUD Royalty should be treated as mineral royalty interests for federal income tax purposes, which generates ordinary income subject to depletion. Please read “Federal income tax considerations.”

Estimated ratio of taxable income to distributions		The trust estimates that if you own the units you purchase in this offering through the record date for distributions for the period ending December 31, 2012, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, the trust estimates that your average allocable federal taxable income per year will be no more than approximately $ per unit. Please read “Federal income tax considerations.”

RISK FACTORS

Drilling and completion of the PUD Wells on the Underlying Properties are high risk activities with many uncertainties that could delay ECA’s anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders.

The drilling and completion of the PUD Wells on the Underlying Properties are subject to numerous risks beyond ECA’s and the trust’s control, including risks that could delay ECA’s current drilling schedule for the PUD Wells and the risk that drilling will not result in commercially viable natural gas production. ECA’s decisions to develop or otherwise exploit certain areas within the AMI will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. ECA’s costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, ECA’s future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:


	•	delays imposed by or resulting from compliance with regulatory requirements including permitting;

	•	unusual or unexpected geological formations;

	•	shortages of or delays in obtaining equipment and qualified personnel;

	•	equipment malfunctions, failures or accidents;

	•	lack of available gathering facilities or delays in construction of gathering facilities;

	•	lack of available capacity on interconnecting transmission pipelines;

	•	unexpected operational events and drilling conditions;

	•	pipe or cement failures;

	•	casing collapses;

	•	lost or damaged drilling and service tools;

	•	loss of drilling fluid circulation;

	•	uncontrollable flows of natural gas and fluids;

	•	fires and natural disasters;

	•	environmental hazards, such as natural gas leaks, pipeline ruptures and discharges of toxic gases;

	•	adverse weather conditions;


	•	reductions in natural gas prices;

	•	natural gas property title problems; and

	•	market limitations for natural gas.

In the event that drilling of development wells is delayed or development wells have lower than anticipated production due to one of the factors above or for any other reason, estimated future distributions to unitholders may be reduced.

Natural gas prices fluctuate due to a number of factors that are beyond the control of the trust and ECA, and lower prices could reduce proceeds to the trust and cash distributions to unitholders.

The trust’s reserves and quarterly cash distributions are highly dependent upon the prices realized from the sale of natural gas. Natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the trust and ECA. These factors include, among others:


	•	weather conditions and seasonal trends;

	•	regional, domestic and foreign supply and perceptions of supply of natural gas;

	•	availability of imported liquefied natural gas, or LNG;

	•	the level of demand and perceptions of demand for natural gas;

	•	anticipated future prices of natural gas, LNG and other commodities;

	•	technological advances affecting energy consumption and energy supply;

	•	U.S. and worldwide political and economic conditions;

	•	the price and availability of alternative fuels;

	•	the proximity, capacity, cost and availability of gathering and transportation facilities;

	•	the volatility and uncertainty of regional pricing differentials;

	•	acts of force majeure;

	•	governmental regulations and taxation; and

	•	energy conservation and environmental measures.

From 2006 through 2009 the highest monthly NYMEX settled price was $13.11 per MMBtu and the lowest was $2.84 per MMBtu. In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season.

Lower natural gas prices will reduce proceeds to which the trust is entitled and may ultimately reduce the amount of natural gas that is economic to produce from the Underlying Properties. As a result, the operator of any of the Underlying Properties could determine during

periods of low gas prices to shut in or curtail production from wells on the Underlying Properties. In addition, the operator of the Underlying Properties could determine during periods of low gas prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, ECA may abandon any well or property if it reasonably believes that the well or property can no longer produce natural gas in commercially economic quantities. This could result in termination of the portion of the royalty interest relating to the abandoned well or property, and ECA would have no obligation to drill a replacement well. In making such decisions, ECA is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. As a result, the volatility of natural gas prices also reduces the accuracy of estimates of future cash distributions to trust unitholders.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the reserves estimated to be attributable to the trust’s royalty interests. The trust’s reserve quantities and revenues are based on estimates of reserve quantities and revenues for the Underlying Properties. See “The Underlying Properties — Natural gas reserves” for a discussion of the method of allocating proved reserves to the trust. It is not possible to measure underground accumulations of natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary negatively and in material amounts from estimates and those variations could be material. Petroleum engineers are required to make subjective estimates of underground accumulations of natural gas based on factors and assumptions that include:


	•	historical production from the area compared with production rates from other producing areas;

	•	natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and

	•	the assumed effect of governmental regulation.

Changes in these assumptions or actual production costs incurred and results of actual development and production costs could materially decrease reserve estimates.

In particular, reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in estimates of proved reserves, future production rates and the timing of development expenditures. The Producing Wells have been operational for less than one year. Additionally, the use of horizontal drilling methods on the Underlying Properties is a recent development in the Marcellus Shale, with ECA commencing the drilling of its first horizontal well in the Marcellus Shale in 2007. The lack of operational history for horizontal wells in the Marcellus Shale formation may also contribute to the inaccuracy of estimates of proved reserves. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates, including variances attributable to a lack of production history within the Marcellus Shale formation, would have a material adverse effect on the financial condition, results of operations and cash flows of the trust and would reduce cash distributions to trust unitholders.

Recently proposed severance taxes in Pennsylvania could, if enacted, materially increase the applicable taxes that are borne by the trust.

While Pennsylvania has historically not imposed a severance tax on the production of natural gas, legislation known as Senate Bill No. 1254 was introduced in the Pennsylvania Senate Finance Committee on March 4, 2010 and House Bill 1489 was introduced in the House Energy and Environmental Resources Committee on May 13, 2009. These bills, if enacted, would provide for a severance tax of 5% of the value of the natural gas at the wellhead plus $0.047 per thousand cubic feet of natural gas severed. Additionally, a severance tax, with tax rates equal to those of Senate Bill No. 1254 and House Bill 1489, is included in the governor’s proposed 2010-2011 budget, dated February 9, 2010. If adopted, any such severance tax would be a post-production cost that would be borne by the trust and may materially reduce distributions to unitholders.

The generation of proceeds for distribution by the trust depends in part on gathering, transportation and processing facilities owned by ECA and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties.

The amount of natural gas that may be produced and sold from any well to which the Underlying Properties relate is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery of gas, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, ECA is provided limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If ECA is forced to reduce production due to such a curtailment, the revenues of the trust and the amount of cash distributions to the trust unitholders would similarly be reduced due to the reduction of proceeds from the sale of production.

Some of the wells on the underlying PUD properties will be drilled in locations that currently are not serviced by gathering and transportation pipelines or locations in which existing gathering and transportation pipelines do not have sufficient capacity to transport additional production. As a result, ECA may not be able to sell the natural gas production from certain PUD Wells until the necessary gathering systems and/or transportation pipelines are constructed or until the necessary transportation capacity on an interstate pipeline is obtained. Any delay in the construction or expansion of these gathering systems beyond the currently estimated construction schedules, or a delay in the procurement of additional transportation capacity would delay the receipt of any proceeds that may be associated with natural gas production from the PUD Wells. If transportation capacity is not available, either directly from a pipeline or pipelines or in the secondary capacity market, ECA would be required to request that the pipeline or pipelines construct additional facilities or expand their existing facilities to provide additional transportation capacity. The pipelines are not required to undertake such construction or expansion. If the pipeline refuses to construct additional transportation capacity or expand its existing transportation capacity, ECA may not be able to receive proceeds that may be associated with natural gas production from wells on the underlying PUD properties. Any delay in the construction or expansion of pipeline transportation facilities will delay the receipt of any proceeds that may be associated with natural gas production from wells on the underlying PUD properties.

The generation of proceeds for distribution by the trust depends in part on the ability of ECA and/or its customers to obtain service on transportation facilities owned by third party pipelines; any limitation in the availability of those facilities and/or any increase in the cost of service on those facilities could interfere with sales of natural gas production from the Underlying Properties.

Natural gas that is gathered on Greene County Gathering System, including natural gas produced from the Underlying Properties, is currently shipped on two interstate natural gas transportation pipelines. ECA’s purchasers have contracted with those pipelines for firm or interruptible transportation service. The rates for service on the transportation pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) and are subject to increase if the pipeline demonstrates that the existing rates are unjust and unreasonable.

ECA may, in the future, seek to obtain firm transportation capacity, but there can be no assurance that capacity will be available. In addition, to the extent ECA’s customers or ECA became dependent on interruptible service, and to the extent that either pipeline receives requests for service that exceed the capacity of the pipeline, the pipeline will honor requests by its firm customers first, and will then allocate remaining capacity, if any, to interruptible shippers. As a result, ECA or its customers may be unable to obtain all or a part of any requested interruptible capacity service on the transportation pipelines. Any inability of ECA or its customers to procure sufficient capacity to transport the natural gas gathered on its Greene County Gathering System will decrease and/or delay the receipt of any proceeds that may be associated with natural gas production from wells on the Underlying Properties. In addition, any increase in transportation rates paid by ECA for production attributable to the trust’s interests will decrease the proceeds received by the trust.

Shortages or increases in costs of equipment, services and qualified personnel could delay the drilling of the PUD Wells and result in a reduction in the amount of cash available for distribution.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly hinder ECA’s ability to perform the drilling obligations and delay completion of the development wells, which would reduce future distributions to trust unitholders.

Due to the trust’s lack of industry and geographic diversification, adverse developments in the trust’s existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders.

The Underlying Properties will be operated for natural gas production only and are focused exclusively in the Marcellus Shale formation in Greene County, Pennsylvania. In particular, the concentration of the Underlying Properties in the Marcellus Shale formation in Greene County, Pennsylvania could disproportionately expose the trust’s interests to operational and regulatory risk in that area. Due to the lack of diversification in industry type and location of the trust’s interests, adverse developments in the natural gas market or the area of the Underlying Properties

could have a significantly greater impact on the trust’s financial condition, results of operations and cash flows than if the trust’s royalty interests were more diversified.

The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

The existence of a material title deficiency with respect to the Underlying Properties can reduce the value or render a property worthless, thus adversely affecting the distributions to unitholders. ECA does not obtain title insurance covering mineral leaseholds. Additionally, undeveloped acreage has greater risk of title defects than developed acreage.

Consistent with industry practice, ECA has not obtained a preliminary title review on the PUD Wells. Prior to the drilling of a PUD Well, ECA intends to obtain a preliminary title review to ensure there are no obvious defects in title to the leasehold. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. ECA’s failure to cure any title defects may render some locations undrillable and cause ECA to lose its rights to production from the Underlying Properties. In the event of such a material title problem, proceeds available for distribution to unitholders and the value of the trust units may be reduced.

The trust is passive in nature and will have no stockholder voting rights in ECA, managerial, contractual or other ability to influence ECA, or control over the field operations of, sale of natural gas from, or development of, the Underlying Properties.

Trust unitholders have no voting rights with respect to ECA and therefore will have no managerial, contractual or other ability to influence ECA’s activities or operations of the gas properties. In addition, pursuant to the Administrative and Drilling Services Agreement, up to 10% of the PUD Wells may be operated by third parties unrelated to ECA until completion of ECA’s drilling obligation, after which ECA may transfer operations of any or all of the trust properties. Such third party operators may not have the operational expertise of ECA within the AMI. Gas properties are typically managed pursuant to an operating agreement among the working interest owners in the properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the trustee nor the trust unitholders has any contractual ability to influence or control the field operations of, sale of natural gas from, or future development of, the Underlying Properties. The trust units are a passive investment that entitle the trust unitholder to only receive cash distributions from the royalty interests and hedging contracts that have been established for the benefit of the trust.

ECA may transfer all or a portion of the Underlying Properties after satisfying its drilling obligations to the trust, subject to specified limitations; any transferee could have a weaker financial position and/or be less experienced in natural gas development and production than ECA.

ECA may at any time transfer all or part of the Underlying Properties, subject to its obligation not to sell any of the underlying PUD properties prior to satisfying its obligation to drill the PUD Wells. You will not be entitled to vote on any transfer of the Underlying Properties, and the trust will not receive any proceeds from any such transfer. Following any material sale or transfer of any of the Underlying Properties, the Underlying Properties will continue to be subject to the PDP and PUD Royalty Interests. The transferee would be responsible for all of ECA’s obligations relating to the royalty interests on the portion of the Underlying Properties transferred, and ECA

would have no continuing obligation to the trust for those properties. Additionally, ECA may enter into farmout or joint venture arrangements with respect to the wells burdened by the trust’s royalty interest. Any transferee, farmout counterparty or joint venture partner could have a weaker financial position and/or be less experienced in natural gas development and production than ECA.

The natural gas reserves estimated to be attributable to the Underlying Properties of the trust are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.

The proceeds payable to the trust from the royalty interests are derived from the sale of the production of natural gas from the Underlying Properties. The natural gas reserves attributable to the Underlying Properties are depleting assets, which means that the reserves of natural gas attributable to the Underlying Properties will decline over time. As a result, the quantity of natural gas produced from the Underlying Properties will decline over time. Based on the estimated production volumes in the reserve report, the gas production from proved producing reserves attributable to the PDP Royalty Interest is projected to decline at an average rate of approximately 9.7% per year over the life of the trust. As a PUD Well is drilled and placed on production, its reserves are expected to decline approximately 37.5% during the first year of production, approximately 14.7% during the next three to five years of production and approximately 8.0% per year for the remainder of the economically productive life of the well. These production characteristics are generally consistent with other development wells in the AMI. The anticipated rate of decline is an estimate and actual decline rates may vary from those estimated.

Future maintenance may affect the quantity of proved reserves that can be economically produced from the Underlying Properties to which the wells relate. The timing and size of these projects will depend on, among other factors, the market prices of natural gas. With the exception of ECA’s commitment to drill the PUD Wells, ECA has no contractual obligation to make capital expenditures on the Underlying Properties in the future. Furthermore, for properties on which ECA is not designated as the operator, ECA has no control over the timing or amount of those capital expenditures. ECA also has the right to non-consent and not participate in the capital expenditures on properties for which it is not the operator, in which case ECA and the trust will not receive the production resulting from such capital expenditures. If ECA or other operators of the wells to which the Underlying Properties relate do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by ECA or estimated in the reserve report.

The trust agreement will provide that the trust’s business activities will be limited to owning the royalty interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the royalty interests. As a result, the trust will not be permitted to acquire other oil and gas properties or royalty interests to replace the depleting assets and production attributable to the trust.

The amount of cash available for distribution by the trust will be reduced by the amount of post-production costs, applicable taxes associated with the trust’s interest, trust expenses, incentive distributions and reimbursement obligations payable to ECA.

The royalty interests and this trust will bear certain costs and expenses that will reduce the amount of cash received by or available for distribution by the trust to the holders of the trust units. These costs and expenses include those described below.


	•	Substantially all of the production from the Producing Wells and the PUD Wells will utilize ECA’s Greene Country Gathering System. The trust will pay the initial Post-Production Services Fee to ECA for use of such system, which includes ECA’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee is fixed until ECA’s obligation to drill the PUD Wells is satisfied; thereafter, ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System, provided the resulting charge does not exceed the prevailing charges in the area for similar services. Additionally, the trust will be charged for the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used.

	•	There currently are no third party post-production costs; however, any third party post-production costs incurred in the future and associated with the trust’s interests will reduce cash received by or available for distribution, including any amounts paid by ECA for transportation on downstream interstate pipelines.

	•	Taxes allocated to or imposed on the trust will include Pennsylvania franchise tax and any applicable property, ad valorem, production, severance, excise and other similar taxes. Currently, there are no taxes in Pennsylvania related to the production or severance of oil and natural gas in Pennsylvania, but there are currently proposals pending in both the Pennsylvania Senate Finance and the House Energy and Environmental Resources Committees to enact a severance tax, and lawmakers may propose other taxes in the future. If adopted, such taxes would be a post-production cost that is borne by the trust.

	•	The trust will bear 100% of trust administrative expenses, including fees paid to the trustee and the Delaware trustee and an annual administrative services fee of $60,000 payable to ECA.

	•	The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees.

	•	ECA will be entitled, during the subordination period, to receive a quarterly incentive distribution from the trust in an amount equal to 50% of the amount by which distributions paid to all unitholders exceed the incentive thresholds described herein. A more detailed description of these distributions is set forth under the caption “Description of the Trust Agreement — Fees and Expenses — Fees to ECA.”


	•	ECA has incurred costs of approximately $5 million in establishing the floor price contracts to be transferred to the trust. ECA will be entitled to reimbursement for these expenditures only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the common and subordinated unitholders. ECA’s reimbursement right will terminate at the end of the subordination period.

The amount of costs and expenses that will be borne by the trust may vary materially from quarter-to-quarter. The extent by which the costs and expenses described above are higher or lower in any quarter will directly decrease or increase the amount received by the trust and available for distribution to the unitholders. For a further summary of post-production costs and applicable taxes for the producing lives of the Producing Wells and PUD Wells, see “The

Underlying Properties.” Historical post-production costs and taxes, however, may not be indicative of future post-production costs and taxes.

A decrease in the differential between the price realized by ECA for natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of trust units.

The prices received for ECA’s natural gas production usually exceed the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. ECA cannot accurately predict natural gas differentials. Decreases in the differential between the realized price of natural gas and the benchmark price for natural gas could reduce the proceeds to the trust and therefore the cash distributions by the trust and the value of the trust units.

ECA has entered into natural gas floor price contracts for the benefit of the trust and will enter into back-to-back swap agreements with the trust that cover only a portion of the estimated natural gas production attributable to the trust’s royalty interests, and such hedging arrangements will terminate after March 31, 2014. The trust’s receipt of any payments due based on these natural gas hedging contracts depends upon the financial position of the hedge contract counterparties. A default by any of the hedge contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

Fifty percent of the estimated natural gas production attributable to the trust’s royalty interests will be hedged from April 1, 2010 through March 31, 2014. As a result, the remaining 50% of estimated production through March 31, 2014 and all production after such date will not be hedged to protect against the price risks inherent in holding interests in natural gas, a commodity that is frequently characterized by significant price volatility. Furthermore, while the use of hedging transactions limits the downside risk of price declines, swaps may also limit the trust’s ability to realize cash flow from natural gas price increases on the portion of the production attributable to the trust’s royalty interests that is hedged. The trust will not have any ability to terminate the swaps before the expiration date.

In the event that any of the counterparties to the natural gas hedging contracts default on their obligations to make payments to the trust under the hedge contracts, the cash distributions to the trust unitholders would likely be materially reduced as the hedge payments are intended to provide additional cash to the trust during periods of lower natural gas prices. ECA will have no continuing obligation with respect to the natural gas floor price contracts. However, ECA will be the trust’s counterparty under the back-to-back swap agreements and will have continuing obligations with respect to these agreements.

Natural gas wells are subject to operational hazards that can cause substantial losses. ECA maintains insurance; however, ECA may not be adequately insured for all such hazards.

There are a variety of operating risks inherent in natural gas production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blow-outs, uncontrollable flow of natural gas, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of natural gas at any of the Underlying Properties will reduce trust distributions by reducing the amount of proceeds available for distribution.

Additionally, if any of such risks or similar accidents occur, ECA could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If ECA experiences any of these problems, its ability to conduct operations and perform its obligations to the trust could be adversely affected. While ECA intends to obtain and maintain insurance coverage it deems appropriate for these risks with respect to the Underlying Properties, ECA’s operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. If a well is damaged, ECA would have no obligation to drill a replacement well or make the trust whole for the loss.

The subordination of certain trust units held by ECA does not assure that you will in fact receive any specified return on your investment in the trust.

Although ECA will not be entitled to receive any distribution on its subordinated units unless there is enough cash for all of the common units to receive a distribution equal to the subordination threshold for such quarter (which is equal to 80% of the target distribution level for the corresponding quarter), the subordinated units constitute only a 25% interest in the trust, and this feature does not guarantee that common units will receive a distribution equal to the subordination threshold, or any distribution at all. Additionally, the subordination period will terminate and the subordinated units will convert into common units four quarters following ECA’s completion of its drilling obligation. Depending on the prices at which ECA is able to sell volumes attributable to the trust, the common units may receive a distribution that is below the subordination threshold.

Estimates of future cash distributions to unitholders, subordination thresholds and incentive thresholds are based on assumptions that are inherently subjective and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual cash distributions to differ materially from those estimated.

The estimates of target distributions to unitholders, subordination thresholds and incentive thresholds, as set forth in “Target Distributions and Subordination and Incentive Thresholds,” are based on ECA’s calculations, and ECA has not received an opinion or report on such calculations from any independent accountants. Such calculations are based on assumptions about drilling, production, natural gas prices, hedging activities, capital expenditures, expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that natural gas production is sold at prices consistent with NYMEX forward pricing as of March 11, 2010 for the thirty-six month period ending March 31, 2013 and increased thereafter by a 2.5% annual escalator (as adjusted for a basis differential of $0.15 per MMBtu escalated at 2.5% annually starting in the second quarter of 2013), capped at $9.00 per MMBtu starting in 2025; however, actual sales prices may be significantly lower. Additionally, these estimates assume that the PUD Wells will be drilled on ECA’s current anticipated schedule and the related Underlying Properties will achieve production volumes set forth in the reserve report; however, the drilling of the development wells may be delayed and actual production volumes may be significantly lower.

Furthermore, the subordination thresholds for each quarter during the subordination period do not represent distributions you should expect to receive. To the extent actual cash distributions differ materially from those set forth in the estimates underlying target distributions, the actual distributions you receive may be lower than the target distribution and the subordination threshold for the applicable quarter. A cash distribution to trust unitholders below

the target distribution amount or the subordination threshold may materially adversely affect the market price of the trust units.

The trustee may, under certain circumstances, sell the royalty interests and dissolve the trust. The trust will begin to terminate following the end of the 20-year period in which the trust owns the Term Royalties.

The trustee must sell the royalty interests if the holders of a majority of the trust units approve the sale or vote to dissolve the trust. The trustee must also sell the royalty interests if the gross proceeds to the trust are less than $1.5 million for any four consecutive quarters. Sale of all the royalty interests will result in the dissolution of the trust. The net proceeds of any such sale will be distributed to the trust unitholders. The trust will begin to liquidate on the Termination Date. The trust unitholders will not be entitled to receive any proceeds from the sale of production from the Underlying Properties following such date. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders (including ECA to the extent of any trust units it owns) at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date. A more detailed description of this right of first refusal is set forth under the caption “The Trust.”

ECA and the Private Investors may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the closing of the offering, ECA will hold an aggregate of 3,395,433 common units and 4,500,000 subordinated units. In addition, the Private Investors will hold 1,104,567 common units. All of the subordinated units will automatically convert into common units at the end of the subordination period, which is currently expected to occur on April 1, 2014. ECA and the Private Investors have agreed not to sell any trust units for a period of 180 days after the date of this prospectus without the consent of Raymond James & Associates, Inc. and Citigroup Global Markets Inc., acting as representatives of the several underwriters. See “Underwriting.” After such period, ECA and the Private Investors may sell trust units in the public or private markets, and any such sales could have an adverse impact on the price of the common units or on any trading market that may develop. ECA has granted registration rights to the Private Investors which, if exercised, would facilitate sales of common units by such holders. In addition, ECA would have the ability to register common units for sale on its own behalf.

There has been no public market for the common units and no independent appraisal of the value of the royalty interests has been performed.

The initial public offering price of the common units will be determined by negotiation among ECA and the underwriters. Among the factors to be considered in determining the initial public offering price, in addition to prevailing market conditions, will be current and historical natural gas prices, current and prospective conditions in the supply and demand for natural gas, reserve and production quantities estimated for the royalty interests and the trust’s cash distributions prospects. None of ECA, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the royalty interests other than the reserve report prepared by Ryder Scott.

Conflicts of interest could arise between ECA and the trust unitholders.

As a working interest owner in the Underlying Properties, ECA could have interests that conflict with the interests of the trust and the trust unitholders. For example:


	•	Notwithstanding its drilling obligation to the trust, ECA’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, ECA may abandon a well which is uneconomic to it while such well is still generating revenue for the trust unitholders. Subsequent to fulfilling its drilling obligation, ECA may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.

	•	ECA may sell some or all of the Underlying Properties, subject to its obligation not to sell any of the underlying PUD properties prior to satisfying its obligation to drill the PUD Wells. Such sale may not be in the best interests of the trust unitholders. Any purchaser may lack ECA’s experience in the Marcellus Shale or its credit worthiness.

	•	ECA may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with the sale by ECA of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests. See “The Underlying Properties — Sale and abandonment of Underlying Properties.”

	•	After it has completed its drilling obligation, ECA may in its discretion increase its Post-Production Services Fee for post-production costs on its Greene County Gathering System to the extent necessary to recover certain capital expenditures on the Greene County Gathering System.

	•	ECA is permitted under the conveyance agreements creating the royalty interests to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and ECA will deduct from the trust’s proceeds any charges under such contracts attributable to production from the trust properties. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of ECA relating to processing or transportation of natural gas must be comparable to charges prevailing in the area for similar services.

	•	ECA has registration rights and can sell its units without considering the effects such sale may have on common unit prices or on the trust itself. Additionally, ECA can vote its trust units in its sole discretion.

The trust is managed by a trustee who cannot be replaced except at a special meeting of trust unitholders.

The business and affairs of the trust will be managed by the trustee. Your voting rights as a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the outstanding trust units, including trust units held by ECA, at a special meeting of trust unitholders called by either the trustee or

the holders of not less than 10% of the outstanding trust units. As a result, it will be difficult for public unitholders to remove or replace the trustee without the cooperation of ECA (so long as it holds a significant percentage of total trust units) or other holders of a substantial percentage of the outstanding trust units.

Trust unitholders have limited ability to enforce provisions of the royalty interests, and ECA’s liability to the trust is limited.

The trust agreement permits the trustee and the trust to sue ECA or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the PDP and PUD Royalty Interests. If the trustee does not take appropriate action to enforce provisions of these conveyances, trust unitholders’ recourse would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits a trust unitholder’s ability to directly sue ECA or any other third party other than the trustee. As a result, trust unitholders will not be able to sue ECA or any future owner of the Underlying Properties to enforce these rights. Furthermore, the royalty interest conveyances provide that, except as set forth in the conveyances, ECA will not be liable to the trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts in good faith.

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

ECA is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose ECA to significant liabilities.

ECA’s natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, ECA must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. ECA may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, ECA’s costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to ECA’s operations. Such costs could have a material adverse effect on ECA’s business, financial condition and results of operations. ECA must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent ECA is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Laws and regulations governing natural gas exploration and production may also affect production levels. ECA is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the natural gas properties; the establishment of maximum rates of production from natural gas wells; the spacing of wells; the plugging and abandonment of wells; and removal of related production equipment. These and other laws and regulations can limit the amount of natural gas ECA can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact trust distributions,

estimated and actual future net revenues to the trust and estimates of reserves attributable to the trust’s interests.

New laws or regulations, or changes to existing laws or regulations may unfavorably impact ECA, could result in increased operating costs and have a material adverse effect on ECA’s financial condition and results of operations. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in natural gas and oil exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of most U.S. federal tax incentives and deductions available to natural gas exploration and production activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase ECA’s operating costs, reduce ECA’s liquidity, delay ECA’s operations or otherwise alter the way ECA conducts its business, which could have a material adverse effect on ECA’s financial condition, results of operations and cash flows.

The ability of ECA to satisfy its obligations to the trust depends on the financial position of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in the event of ECA’s bankruptcy, it may be expensive and time-consuming for the trust to exercise its remedies.

ECA is a privately held, independent energy company engaged in the exploration, development, production, gathering and aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. Pursuant to the terms of the Administrative and Drilling Services Agreement, ECA will be obligated to drill the PUD Wells at its own expense. ECA is also the operator of all of the Producing Wells and will agree to operate substantially all of the PUD Wells until completion of its drilling obligation. The conveyances also provide that ECA will be obligated to market, or cause to be marketed, the natural gas production related to the Underlying Properties. Additionally, ECA will be the counterparty to the trust’s hedging swap agreements and will have continuing obligations with respect to these agreements. Due to the trust’s reliance on ECA to fulfill these numerous obligations, the value of the trust’s royalty interest and its ultimate cash available for distribution will be highly dependent on ECA’s performance. ECA will not be a reporting company following this offering and will not file periodic reports with the SEC. Therefore, as a trust unitholder, you will not have access to financial information of ECA.

The ability of ECA to perform these obligations will depend on ECA’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for natural gas and oil, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of ECA. See “Information about Energy Corporation of America” found on page ECA-1 for additional information relating to ECA, including information relating to the business of ECA, historical financial statements of ECA and other financial information relating to ECA.

In the event that ECA defaults on its obligation to drill the PUD Wells, the trust’s remedy would be to foreclose on the trust’s Drilling Support Lien on all of ECA’s remaining interests in the AMI to recover the security interest in the amount of $91 million, which amount will be reduced proportionately as each PUD Well is drilled. The process of foreclosing on such collateral may be expensive and time-consuming and delay the drilling and completion of the PUD Wells; such delays and expenses would reduce trust distributions by reducing the amount of proceeds available for distribution. The amount of the security interest recovered is required to be applied to completion of the drilling obligations of ECA, will not result in any distribution to the trust unitholders and may be insufficient to drill the number of wells needed for the trust to realize the full value of the PUD Royalty Interest. Furthermore, the trust would have to seek a

new party to perform the drilling and operations of the wells. The trust may not be able to find a replacement driller or operator, and it may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time.

Due to uncertainty under the laws of Pennsylvania, there is a risk that the royalty interests conveyed by ECA to the trust would not be treated as real property interests, or interests in hydrocarbons in place or to be produced. As a result, the royalty interests might be treated as unsecured claims of the trust against ECA in the event of ECA’s bankruptcy. The Royalty Interest Lien is intended to provide security to the trust should the royalty interests be subject to such a challenge. If the PDP Royalty Interest or the PUD Royalty Interest were determined not to be a real property interest owned by the trust, the trust’s remedy would be to foreclose on the trust’s Royalty Interest Lien to cause the trust to receive a volume of natural gas production from the trust properties calculated in accordance with the provisions of the conveyances of the royalty interests to the trust. Foreclosure on the Royalty Interest Lien is exercisable only following a bankruptcy filing of ECA or its successor and based on an uncured payment default occurring under the conveyances of the royalty interests to the trust existing at the time of, or occurring after, such bankruptcy filing. Similar to the Drilling Support Lien, the process of foreclosing to enforce the Royalty Interest Lien may be expensive and time-consuming; and the resulting delays and expenses would reduce trust distributions by reducing the amount of proceeds available for distribution.

The proceeds of the royalty interests may be commingled, for a period of time, with proceeds of ECA’s retained interest. It is possible that the trust may not have adequate facts to trace its entitlement to funds in the commingled pool of funds and that other persons may, in asserting claims against ECA’s retained interest, be able to assert claims to the proceeds that should be delivered to the trust. In addition, during a bankruptcy of ECA, it is possible that payments of the royalties may be delayed or deferred. It is also possible that the obligation to pay royalties will be disaffirmed or cancelled. In either situation, the trust may need to look to the Royalty Interest Lien to replace its rights under the royalty interests. During the pendency of ECA’s bankruptcy proceedings, the trust’s ability to foreclose on the Drilling Support Lien or the Royalty Interest Lien, and the ability to collect cash payments from customers being held in ECA’s accounts that are attributable to production from the trust properties, may be stayed by the bankruptcy court. Delay in realizing on the collateral for the Drilling Support Lien and the Royalty Interest Lien is possible, and it cannot be guaranteed that a bankruptcy court would permit such foreclosure. It is possible that the bankruptcy would also delay the execution of a new agreement with another driller or operator. If the trust enters into a new agreement with a drilling or operating partner, the new partner might not achieve the same levels of production or sell natural gas at the same prices as ECA was able to achieve.

ECA’s performance of its drilling obligations to the trust and the financial results of the trust may not be as successful as the drilling and financial results of Eastern American Natural Gas Trust or ECA’s other royalty interest ventures.

As disclosed in this prospectus, ECA previously sponsored the formation of Eastern American Natural Gas Trust, and ECA has previously sold term royalty interests in a separate transaction to private investors. The historical results of operations and performance of the Eastern American Natural Gas Trust should not be relied on as an indicator of how this trust will perform.

The operations of ECA are subject to environmental laws and regulations that may result in significant costs and liabilities.

The natural gas exploration and production operations of ECA in the Marcellus Shale are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to ECA’s operations including the acquisition of a permit before conducting drilling; water withdrawal or waste disposal activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of ECA’s operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of ECA’s operations due to its handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, ECA could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether ECA was responsible for the release or contamination or if the operations were not in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which ECA’s wells are drilled and facilities where ECA’s petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose ECA to significant liabilities that could have a material adverse effect on its financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require ECA to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. ECA may not be able to recover some or any of these costs from insurance. As a result of the increased cost of compliance, ECA may decide to discontinue drilling. Additionally, permitting delays may inhibit ECA’s ability to drill the PUD Wells on schedule.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas that ECA produces while the physical effects of climate change could disrupt ECA’s production and cause ECA to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment. These findings allow the agency to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting

of GHG emissions from specified large GHG emission sources in the United States, beginning in 2011 for emissions occurring in 2010. Only very recently, on March 23, 2010, the EPA announced a proposed rulemaking that would expand its final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, monitoring of those newly covered sources would commence on January 1, 2011. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” (“ACESA”), which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, ECA’s equipment and operations could require ECA to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas that it produces. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on ECA’s assets and operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect ECA’s services.

The U.S. Congress is considering legislation that would amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act. Hydraulic fracturing is an important and commonly used process for the completion of natural gas wells, and to a lesser extent, oil wells, in formations with low permeabilities, such as shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the legislation have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the legislation could result in additional regulatory burdens involving permitting, construction standards for wells, monitoring, recordkeeping and closure of wells. The legislation also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For instance, the New York Department of Environmental Conservation announced in April 2010 that the watershed relied upon by New York City as a source of drinking water would be excluded from the pending generic environmental review process, thereby requiring natural gas operators seeking to drill in the watershed, which is located in the Marcellus Shale region, to pursue a case-by-case environmental review to establish whether appropriate measures to mitigate potential impacts can be developed. Moreover, the Pennsylvania Department of Environmental Protection has

adopted a new permitting policy concerning surface water discharges from wastewater treatment facilities handling flowback fluids and produced waters from oil and gas well sites that could result in increased requirements for treatment of these fluids and limitations on their discharge to receiving waters. The adoption of the pending congressional legislation or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult for ECA to complete natural gas wells in the Marcellus Shale as well as increase its costs of compliance and doing business. Moreover, on March 18, 2010, the EPA announced that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing activities. If ECA is unable to remove and dispose of water at a reasonable cost and within applicable environmental rules, ECA’s ability to produce gas commercially and in commercial quantities from the Underlying Properties could be impaired.

Tax Risks Related to the Trust’s Common Units

The trust’s tax treatment depends on its status as a partnership for federal income tax purposes. If the IRS were to treat the trust as a corporation for federal income tax purposes, then its cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the trust units depends largely on the trust being treated as a partnership for federal income tax purposes. The trust has not requested, and does not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting it.

It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such as the trust, to be treated as a corporation for federal income tax purposes. Although the trust does not believe based upon its current activities that it is so treated, a change in current law could cause it to be treated as a corporation for federal income tax purposes or otherwise subject it to taxation as an entity.

If the trust was treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely be required to pay state income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon the trust as a corporation, its cash available for distribution to you would be substantially reduced. Therefore, treatment of the trust as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the trust unitholders, likely causing a substantial reduction in the value of the trust units.

The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the trust to taxation as a corporation or otherwise subjects it to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on the trust.

If the trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the trust’s cash available for distribution to you would be reduced.

The trust will be required to pay Pennsylvania franchise tax on its capital stock value, as determined pursuant to the statute and apportioned to Pennsylvania. The current tax rate of 0.289% is currently scheduled to be reduced to 0.189% in 2012 and 0.089% in 2013 and to be completely phased out in 2014. This schedule may be altered and the taxes left in place subject to the General Assembly in its annual budget process. Changes in current state law may subject the trust to additional entity-level taxation by Pennsylvania or other states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any additional taxes on the trust may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in the trust units. The trust agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects the trust to additional amounts of entity-level taxation for state or local income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law on the trust.

The tax treatment of an investment in trust units could be affected by recent and potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The recently enacted Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects an individual having adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns) to an additional “medicare tax” equal generally to 3.8% of the lesser of such excess or the individual’s net investment income, which appears to include interest income and royalty income derived from investments such as the trust units as well as any net gain from the disposition of trust units. In addition, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

Current law may change so as to cause the trust to be treated as a corporation for federal income tax purposes or otherwise subject the trust to entity-level taxation. Specifically, the present federal income tax treatment of publicly traded partnerships, including the trust, or an investment in the trust units may be modified by administrative, legislative or judicial interpretation at any time. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to the trust as currently proposed, it could be amended prior to enactment in a manner that does apply to the trust.

The trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests the federal income tax positions the trust takes, the value of the trust units may be adversely affected, the cost of any IRS contest will reduce the trust’s cash available for distribution to you and income, gain, loss and deduction may be reallocated among trust unitholders.

The trust will treat each purchaser of common units as having the same economic attributes without regard to the actual common units purchased. Moreover, the trust will generally prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the first day of each month, instead

of on the basis of the date a particular trust unit is transferred. Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of these methods may not be permitted under existing Treasury Regulations. If the IRS contests the federal income tax positions the trust takes, the market for the trust units may be adversely impacted, the cost of any IRS contest will reduce the trust’s cash available for distribution to you and items of income, gain, loss and deduction may be reallocated among trust unitholders.

If the IRS contests the federal income tax positions the trust takes, the market for the trust units may be adversely impacted and the cost of any IRS contest will reduce the trust’s cash available for distribution to you.

The trust has not requested a ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter affecting the trust. The IRS may adopt positions that differ from the conclusions of the trust’s counsel expressed in this prospectus or from the positions the trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some or all of the conclusions of the trust’s counsel or the positions the trust takes. A court may not agree with some or all of the conclusions of the trust’s counsel or positions the trust takes. Any contest with the IRS may materially and adversely impact the market for the trust units and the price at which they trade. In addition, the trust’s costs of any contest with the IRS will be borne indirectly by the trust unitholders because the costs will reduce the trust’s cash available for distribution.

You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.

Because the trust unitholders will be treated as partners to whom the trust will allocate taxable income which could be different in amount than the cash the trust distributes, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of the trust’s taxable income even if you receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your share of the trust’s taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of the trust units could be more or less than expected.

If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. Because distributions in excess of your allocable share of the trust’s net taxable income decrease your tax basis in your trust units, the amount, if any, of such prior excess distributions with respect to the trust units you sell will, in effect, become taxable income to you if you sell such trust units at a price greater than your tax basis in those trust units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion recapture. Please read “Federal Income Tax Considerations — Disposition of Trust Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning the trust units that may result in adverse tax consequences to them.

Investment in trust units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons may be required to file U.S. federal income tax returns and pay tax on

their share of the trust’s taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult a tax advisor before investing in the trust units.

The trust will treat each purchaser of trust units as having the same economic attributes without regard to the actual trust units purchased. The IRS may challenge this treatment, which could adversely affect the value of the trust units.

Due to a number of factors, including the trust’s inability to match transferors and transferees of trust units, the trust will adopt positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of trust units and could have a negative impact on the value of the trust units or result in audit adjustments to your tax returns. Please read “Federal Income Tax Considerations — Tax Consequences of Trust Unit Ownership — Section 754 Election.”

The trust will prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the first day of each month, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.

The trust will generally prorate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the first day of each month, instead of on the basis of the date a particular trust unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, the trust’s counsel is unable to opine as to the validity of this method. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method the trust will adopt. If the IRS were to challenge the trust’s proration method, the trust may be required to change its allocation of items of income, gain, loss and deduction among the trust unitholders. Please read “Federal Income Tax Considerations — Disposition of Trust Units — Allocations Between Transferors and Transferees.”

A trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of those trust units. If so, he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition.

Because a trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of the loaned trust units, he may no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of the trust’s income, gain, loss or deduction with respect to those trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those trust units could be fully taxable as ordinary income. The trust’s counsel has not rendered an opinion regarding the treatment of a unitholder where trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their trust units.

The trust will adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the trust unitholders. The IRS may challenge this treatment, which could adversely affect the value of the trust units.

The federal income tax consequences of the ownership and disposition of trust units will depend in part on the trust’s estimates of the relative fair market values, and the initial tax bases of the trust’s assets. Although the trust may from time to time consult with professional appraisers regarding valuation matters, the trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

The sale or exchange of 50% or more of the trust’s capital and profits interests during any twelve-month period will result in the termination of the trust’s partnership status for federal income tax purposes.

The trust will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in its capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same trust unit within any 12 month period will be counted only once. The trust’s termination would, among other things, result in the closing of its taxable year for all trust unitholders, which would result in the trust filing two tax returns (and the trust unitholders could receive two Schedules K-1) for one calendar year. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurs. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of the trust’s taxable year may also result in more than twelve months of the trust’s taxable income being includable in his taxable income for the year of termination. A technical termination would not affect the trust’s classification as a partnership for federal income tax purposes, but instead, the trust would be treated as a new partnership for tax purposes. If treated as a new partnership, the trust must make new tax elections and could be subject to penalties if the trust is unable to determine that a technical termination occurred.

Certain federal income tax preferences currently available with respect to natural gas production may be eliminated as a result of future legislation.

Among the changes contained in President Obama’s Budget Proposal for Fiscal Year 2011 (the “2011 Budget”) is the elimination of certain key U.S. federal income tax preferences relating to natural gas exploration and production. The 2011 Budget proposes to eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources effective in 2011. Specifically, the 2011 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, including interests such as the Perpetual Royalty Interests, in which case only cost depletion would be available.

FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” about ECA and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under “Summary” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of ECA and the activities of the trust are forward-looking statements.

Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Target Distributions and Subordination and Incentive Thresholds,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.

When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this document, could affect the future results of the energy industry in general, and ECA and the trust in particular, and could cause those results to differ materially from those expressed in such forward-looking statements:


	•	risks incident to the drilling and operation of natural gas wells;

	•	future production and development costs;

	•	the effect of existing and future laws and regulatory actions;


	•	the effect of changes in commodity prices, the ability of the trust’s hedge counterparties, including ECA, to meet their contractual obligations and conditions in the capital markets;


	•	competition from others in the energy industry; and

	•	uncertainty of estimates of natural gas reserves and production.

This prospectus describes other important factors that could cause actual results to differ materially from expectations of ECA and the trust, including under the heading “Risk Factors.” All written and oral forward-looking statements attributable to ECA or the trust or persons acting on behalf of ECA or the trust are expressly qualified in their entirety by such factors.

USE OF PROCEEDS

The trust is offering the common units to be sold in this offering. Assuming no exercise of the underwriters’ over-allotment option and an initial public offering price of $ per common unit, the estimated net proceeds of this offering will be approximately $ million, after deducting underwriting discounts and commissions and offering expenses. The trust will use the net proceeds to pay ECA’s wholly-owned subsidiary for the conveyance of the Term Royalties. In turn, such subsidiary will use all of such amount to repay a $ million demand note payable to ECA issued as consideration for the transfer of the Term Royalties thereto.

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions, to increase or decrease by $ million. If the proceeds increase due to a higher initial public offering price, the trust will distribute the additional proceeds to ECA as consideration for its contribution of the Perpetual Royalties. A reduction in proceeds due to a lower initial public offering price will decrease the amount of proceeds paid to ECA’s subsidiary. The note held by ECA is non-recourse to the trust.

The trust will use the net proceeds from any exercise of the underwriters’ over-allotment option to repurchase an equal number of common units from ECA at the initial public offering price, after deducting underwriting discounts and commissions.

ECA intends to use the proceeds received both from the repayment of the demand note by ECA’s subsidiary and from any exercise of the underwriters’ over-allotment option to purchase 209,316 common units from the Private Investors at the initial public offering price, to reduce borrowings under its revolving credit facility and for general corporate purposes. As of May 6, 2010, the outstanding balance on the revolving credit facility, which matures on July 10, 2012, was approximately $127.4 million, and the weighted average interest rate of the revolving credit facility was 2.3%. Borrowings in the prior year were incurred to fund working capital and capital expenditures. Please read “Certain Transactions.”

NATURAL GAS FUNDAMENTALS IN THE MARCELLUS SHALE

DEMAND FOR NATURAL GAS

Natural gas continues to be a critical component of energy consumption in the United States, accounting for approximately 24.4% of all energy used in 2009, representing approximately 22.8 Tcf of natural gas, according to the U.S. Energy Information Administration (“EIA”). According to the EIA, during the period from 2001 through 2009, natural gas consumption increased by 2.7% overall from an average of approximately 60.9 Bcf per day in 2001 to an average of approximately 62.6 Bcf per day in 2009.

The EIA estimates that real gross domestic product will grow by 2.4% per year from 2008 to 2035 (Annual Energy Outlook 2010). Over the same period, the EIA estimates that total domestic energy consumption will increase by over 19%. Consumption of natural gas is projected to continue to increase through this period due to:


	•	domestic economic and population growth;

	•	added capacity of natural gas-fired, as opposed to coal-fired, electricity generation;

	•	growth in the application of natural gas as a fuel source as a means of diversifying away from foreign oil, such as in natural gas vehicles; and

	•	indirectly through additions of electric vehicles.

NATURAL GAS RESERVES AND PRODUCTION

Historically, the majority of the domestic natural gas supply has been produced from onshore and offshore conventional sources and is supplemented by production from historically declining pipeline imports from Canada, imports of liquefied natural gas (“LNG”) from foreign sources as well as some production in Alaska. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset an established trend of depletion associated with these conventional sources as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in natural gas production has emerged with the increased contribution of natural gas from unconventional resources, defined by the EIA as natural gas produced from shale formations and coalbeds. The emergence of these unconventional resources has been made possible through advances in technology that have allowed producers to extract significant volumes of natural gas from these unconventional plays at cost-advantaged per unit economics versus most conventional sources.

The U.S. Geological Service, Mineral Management Service and EIA estimate that in 2010 the U.S. possesses over 2,000 Tcf of technically recoverable natural gas resources, representing a 92 year reserve life based on current production levels, an increase of approximately 30% from 2008 estimates of technically recoverable natural gas resources, which is primarily driven by shale gas and other unconventional sources. As total energy consumption increases and the depletion of onshore and offshore conventional resources continues, natural gas from unconventional resources is forecast to continue to gain market share from higher-cost conventional sources of natural gas. Natural gas production from shale formations is forecast to provide the majority of the growth in unconventional natural gas supply, increasing to approximately 26% of total U.S. natural gas supply in 2035 as compared with 11.5% in 2009. This represents a projected two-fold increase in natural gas shales’ market share of U.S. natural gas supply. The chart below illustrates the composition of the EIA’s forecasted natural gas production through 2035.

OVERVIEW OF THE MARCELLUS SHALE

The Marcellus Shale formation is the most expansive shale gas play in the U.S., spanning six states in the northeastern U.S. In its April 2009 Modern Shale Gas: A Primer, the United States Department of Energy quoted an estimated potential recoverable resource in the Marcellus Shale formation of over 260 Tcf of gas. The Marcellus Shale is a black, organic rich shale formation located at depths between 4,000 and 8,500 feet, covering approximately 95,000 square miles at an average thickness of 50 ft to 200 ft. In the area of the Underlying Properties in Greene County, Pennsylvania, the Marcellus Shale ranges in thickness from 135 feet to 180 feet.

The first commercial well drilled and completed in the Marcellus Shale was in 2005 in Pennsylvania. Since the beginning of 2007, there have been approximately 2,700 wells permitted in Pennsylvania in the Marcellus Shale and over 1,050 of the approved wells have been drilled.

In 2009, more than 550 wells were drilled in the Marcellus Shale, making it one of the most active and prominent shale gas plays in the U.S., and it is expected to continue to be an area of active, widespread drilling. During 2009, there were more than 50 operators active in the play.

Advances in modern drilling and completion technologies, such as horizontal drilling and hydraulic fracturing, have increased the value potential for many properties in Appalachia by enabling better exploitation of the Marcellus Shale formation and other unconventional reservoirs that are challenging to produce efficiently. In general, horizontal wells use directional drilling to create one or more lateral legs designed to allow the well bore to stay in contact with the reservoir longer and to intersect more vertical fractures in the formation than conventional methods. These lateral legs can be several thousand feet long. While it is more expensive than vertical drilling on a per well basis, horizontal drilling may improve overall returns on investment by increasing recovery volumes and rates, limiting the number of wells necessary to develop an area and reducing the costs and surface disturbances caused by multiple vertical wells. Horizontal drilling and completion techniques have shown improvements in terms of costs and drilling times throughout the Marcellus Shale. ECA has increased the productivity of its operations in Appalachia which target development of the Marcellus Shale formation through the use of horizontal drilling.

ENERGY CORPORATION OF AMERICA

ECA is a privately held energy company engaged in the exploration, development, production, gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and ECA is one of the largest natural gas operators in the Appalachian Basin. As of December 31, 2009, ECA operated approximately 5,100 wells in the Appalachian Basin and had an aggregate leasehold position of approximately one million gross acres with 85% of this acreage held by production. ECA sells gas from its own wells as well as third-party wells to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. ECA owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities. During the fiscal year ended June 30, 2009, ECA and its affiliates aggregated and sold 22.5 Bcf of gas for an average of 62 MMcf of gas per day, of which 20.7 Bcf, or 57 MMcf per day, represented sales of gas produced from wells operated by ECA.

Substantially all of the production subject to the PDP Royalty Interest and PUD Royalty Interest will be gathered by ECA’s Greene County Gathering System. This system currently accesses two separate interconnects with the Texas Eastern Transmission, L.P. and Columbia Gas Transmission, L.L.C. interstate pipeline systems and includes six (6) compressors (with 8,860 total horsepower) together with associated processing equipment. ECA’s interconnect agreements with these interstate pipelines currently allow it to deliver at the interconnections between ECA’s facilities and the interstate pipelines up to a total of 110,000 MMBtu per day for transportation by the interstate pipelines to ECA’s customers (approximately 16,000 MMBtu per day is currently being utilized), which is in excess of its current and expected volumes from the Underlying Properties. To the extent necessary, ECA will add additional compression and related facilities to this system at no cost to the trust, other than potential increases to the Post-Production Service fee to the extent necessary to recover certain capital expenditures after drilling is complete.

ECA was formed in September 1992 as a Colorado corporation and subsequently reincorporated in West Virginia through a merger in June 1995. ECA’s predecessor began operating in the Appalachian Basin in 1963. ECA’s principal offices are located at 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237, and its telephone number is (303) 694-2667. For additional information concerning ECA, see “Information about Energy Corporation of America” beginning on page ECA-1 of this prospectus. ECA will not be a reporting company following this offering and will not file periodic reports with the SEC. Therefore, as a trust unitholder, you will not have access to the financial information of ECA.

The trust units do not represent interests in or obligations of ECA.

SUMMARY CONSOLIDATED FINANCIAL DATA OF ECA

The summary consolidated financial data presented below should be read in conjunction with the audited consolidated financial statements and the unaudited condensed consolidated financial statements of ECA and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Energy Corporation of America” included elsewhere in this prospectus. The following summary consolidated financial data of ECA as of, and for the years ended, June 30, 2007, 2008 and 2009 have been derived from ECA’s audited consolidated financial statements included elsewhere in this prospectus. The following summary consolidated financial data of ECA as of December 31, 2009 and for the six-month periods ended December 31, 2008 and 2009 have been derived from ECA’s unaudited interim condensed consolidated financial statements. The unaudited financial statements were prepared on a basis consistent with the audited statements and, in the opinion of ECA, include all adjustments (consisting only of normal recurring adjustments) necessary to present fairly the results of ECA for the periods presented.


							Six Months Ended
	Year Ended June 30,						December 31,
Historical Results	2007		2008		2009		2008		2009
	(Dollars in thousands, except per share and reserve data)						(Unaudited)

Operating revenue	$	211,954	$	247,071	$	216,220	$	125,110	$	85,040
Income from operations		40,658		51,912		30,350		15,478		11,989
Earnings per common share basic and diluted		33.66		19.93		36.98		25.39		2.85
Dividends declared		11.23		12.50		12.50		6.25		6.50
Total assets		413,321		557,980		543,719		538,501		534,025
Total long-term debt		135,166		197,125		218,134		213,490		237,779
Production (MMcfe) — (unaudited)		9,636		10,684		9,646		5,099		5,464
Net proved developed reserves (MMcfe) — (unaudited)		173,474		176,672		145,102		—		—

MANAGEMENT OF ECA

The executive officers and directors of ECA are listed below, together with a description of their experience and certain other information. All of the directors were elected or re-elected for a one-year term at ECA’s December 2009 annual meeting of stockholders. Executive officers are appointed by the Board of Directors.


Name	Age		Position with ECA or its Subsidiaries

John Mork		62	President and Chief Executive Officer
Michael S. Fletcher		61	Chief Financial Officer
Donald C. Supcoe		53	Senior Vice President, Secretary and General Counsel
J. Michael Forbes		49	Vice President and Treasurer
Kyle M. Mork		30	Vice President of Eastern Operations
George V. O’Malley		58	Vice President Accounting
W. Gaston Caperton, III		70	Director
Peter H. Coors		63	Director
L.B. Curtis		85	Director (Chairman Emeritus)
John J. Dorgan		86	Director
John S. Fischer		59	Director
Thomas R. Goodwin		66	Director (Chairman)
F.H. McCullough, III		62	Director
Julie M. Mork		59	Director
Jerry W. Neely		73	Director
Arthur C. Nielsen, Jr.		90	Director
Jay S. Pifer		72	Director

John Mork has been President and Chief Executive Officer of ECA and a Director of ECA since its formation. Mr. Mork served in various capacities at Union Oil Company until 1972 when he joined Pacific States Gas and Oil, Inc. and subsequently founded Eastern American Energy Corporation (“EAEC”). Mr. Mork was President and a Director of EAEC from 1973 until 1993 with the incorporation of ECA. Mr. Mork is a past Director of the Independent Petroleum Association of America, and the Independent Oil and Gas Association of West Virginia. Mr. Mork was a member of and held various positions with the Young Presidents’ Organization from 1984 until 1998. He also founded the Mountain State Chapter of the Young Presidents’ Organization located in Charleston, West Virginia. He is currently a member of the Chief Executives Organization, the World Presidents’ Organization, the University of Southern California Engineering School Board of Councilors and the University of Southern California Board of Trustees. Mr. Mork holds a Bachelor of Science Degree in Petroleum Engineering from the University of Southern California and is a graduate of the Stanford Business School Program for Chief Executive Officers. Mr. Mork serves on the Board of Directors of the ECA Foundation, Inc. He is the husband of Julie Mork and the father of Kyle Mork.

Michael S. Fletcher has been Chief Financial Officer of ECA since December 1999. He also held the position of Treasurer of ECA from December 1999 through December 2000. In addition, Mr. Fletcher was President of Mountaineer Gas Company from 1998 until ECA sold Mountaineer in August 2000. Prior to becoming President in 1998, he held the positions of Senior Vice President and Chief Financial Officer of Mountaineer. Before joining Mountaineer in 1987, Mr. Fletcher was a partner of Arthur Andersen and Company and was employed by that firm for fifteen years. Mr. Fletcher is a Certified Public Accountant and a graduate of Utah State

University with a Bachelor Degree in Accounting. Mr. Fletcher serves on the Board of Directors of the ECA Foundation, Inc.

Donald C. Supcoe has been a Director of the ECA since 2005. He has served as Senior Vice President, Corporate Secretary and General Counsel since 2000 and is responsible for ECA’s operations east of the Mississippi River. Mr. Supcoe was the Senior Vice President of Mountaineer Gas Company from 1998 until its sale in August 2000. Prior to joining Mountaineer in 1998, he was the Vice President, General Counsel and Corporate Secretary of ECA’s predecessor where he held various positions since 1981. Mr. Supcoe is active in the Independent Oil and Gas Association of West Virginia and currently serves as President of that organization. He is also a past Vice President of the Independent Petroleum Association of America. Mr. Supcoe is currently a member of the Board of Directors of Mid-Atlantic Holdings, Inc., and is a Trustee at Large of the Energy and Mineral Law Foundation. Mr. Supcoe graduated from West Virginia University with a Bachelor of Science Degree in Business Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree from West Virginia University College of Law. Mr. Supcoe serves on the Board of Directors of the ECA Foundation, Inc.

J. Michael Forbes is Vice President and Treasurer of ECA. Mr. Forbes has been an officer of ECA since 1995 and prior to that was an officer with its predecessor, which he joined in 1982. Mr. Forbes graduated with a Bachelor of Arts in Accounting and Finance and a minor in Economics from Glenville State College and is a Certified Public Accountant. He also holds a Master of Business Administration from Marshall University and is a graduate of Stanford University’s Program for Chief Financial Officers. Mr. Forbes serves on the board for numerous community organizations, including Thomas Health Systems where he serves as First Vice Chairman, the ECA Foundation, Inc. and is the Past Chairman of the YMCA of the Kanawha Valley.

Kyle M. Mork has been the Vice President of Eastern Operations for ECA since 2006. He began his career with Halliburton Energy Services as a stimulation engineer before moving to ECA in 2003 as a drilling engineer in Houston, Texas. In 2004, he became the Drilling Manager for ECA’s Eastern Region based in Charleston, West Virginia. He graduated in 2002 with a Bachelor of Science Degree in Chemical Engineering from Cornell University, and has taken Master’s level courses in Petroleum Engineering at the University of Southern California. Currently, he is enrolled in the Executive MBA program at the Kellogg Graduate School of Management at Northwestern University and will graduate in June 2010. Kyle also serves on the Board of Directors of the ECA Foundation, Inc., the YMCA of the Kanawha Valley, Energize WV, and the Clay Center for the Arts. He is the son of John and Julie Mork.

George V. O’Malley has been Vice President of Accounting for ECA since December 2002. Before being elected Vice President, Mr. O’Malley served as Director of Accounting. Mr. O’Malley joined its predecessor in April 1991 and served in various capacities including Vice President and Treasurer. Prior to joining ECA, he held various positions in industry and public accounting. Mr. O’Malley currently serves on the Marshall University School of Business and Department of Accountancy and Legal Environment Advisory Boards. He is a former board member and past President of the West Virginia Society of CPA’s and board member of the Independent Oil & Gas Association of West Virginia. Mr. O’Malley graduated from Marshall University with a Bachelor Degree in Accounting and is a Certified Public Accountant.

W. Gaston Caperton, III has been a Director of ECA since 1997. Mr. Caperton has been a successful leader in three diverse fields: business, government and education. He was the principal owner of a large insurance brokerage firm, is a former two-term governor of West Virginia, and is the current President and Chief Executive Officer of The College Board.

Peter H. Coors has been a Director of ECA since 1997. Mr. Coors is the Chairman of Molson Coors Brewing Company and the Chairman of MillerCoors LLC. He received his Bachelor Degree in Industrial Engineering from Cornell University in 1969 and his Master of Business Administration from the University of Denver in 1970. Mr. Coors also serves on the Board of Directors of the University of Colorado Hospital. He is President of the Adolph Coors Foundation, Castle Rock Foundation, and University of Colorado Hospital Foundation. He also serves on the Board of the Denver Area Council of the Boy Scouts of America and is a member of Denver University’s Strategic Panel on Immigration.

L.B. Curtis has been a Director of ECA since 1993. He was Chairman from 1998 through 2006 and is now Chairman Emeritus. Mr. Curtis was a Director of its predecessor from 1988 until 1993. Mr. Curtis is retired from a career at Conoco, Inc. where he held the position of Vice President of Production Engineering with Conoco Worldwide. Mr. Curtis was highly recognized across the petroleum industry in the upstream segment of the industry. He is a member of the American Petroleum Institute and Society of Petroleum Engineers (SPE) and is a trustee of the SPE Foundation. He was instrumental in the design and development of the North Sea ‘tension-leg’ production platform and a member of the Dupont Lavoisier Academy. Mr. Curtis graduated from The Colorado School of Mines with an Engineer of Petroleum Professional Degree.

John J. Dorgan has been a Director of ECA since 1993 and served as a Director of its predecessor in 1992. He is a former Executive Vice President and consultant to Occidental Petroleum Corporation where he had worked in various capacities starting in 1972. He is also a former Director and Chairman of the Finance Committee, Canadian Occidental.

John S. Fischer has been a Director of ECA since 2005. He founded Solid Systems Engineering Co. in 1979 to service high tonnage conveyor systems in the mining, power and primary metals industries; in 2008 the company was acquired by Fenner Dunlop International. In 1994 Mr. Fischer started Air Control Science, Inc. having recognized the need for a firm with innovative technology to focus exclusively on effective design and construction of dust, spillage and fume control systems for the coal-fired power, coal mining and primary metals industries; in 2007 Air Control Science was acquired by CCC Group, Inc. Mr. Fischer has authored and co-authored patents related to leading technology in coal-fired power and primary metals particulate and dust control. Mr. Fischer graduated from the Northwestern University Kellogg Graduate School with a Master of Business Administration. Currently, he is a member of the World Presidents’ Organization and Chief Executives Organization. Mr. Fischer serves on the National Coal Council for the Secretary of Energy, the Board of University of Colorado Leeds Business School and the Board of the Great Lakes Business School in Chennai India.

Thomas R. Goodwin has been a Director of ECA since 2005 and has served as Chairman of the Board of Directors since 2007. Mr. Goodwin is Managing Partner of the law firm of Goodwin and Goodwin, LLP which provides legal advice to ECA. He is a member of the West Virginia State Bar and has appeared before the West Virginia Supreme Court of Appeals and the Fourth Circuit Court of Appeals. He is listed in the Best Lawyers of America and is counselor to corporations and board of directors. He formerly served as the West Virginia State Tax Commissioner and Executive Assistant to the Governor of West Virginia, Chairman of West Virginia Economic Development Authority, Chairman of the West Virginia Municipal Bond Committee, and past member of Board of Advisors of West Virginia University. Mr. Goodwin’s legal expertise is focused on corporate purchases, corporate sales and financing, and complex litigation. He received his law degree from West Virginia University and his Master Degree in Law from Harvard Law School.

F.H. McCullough, III has been a Director of ECA since 1993. He joined EAEC in 1977 and served in various capacities until 1999, including Director from 1978 until 1993. Mr. McCullough

is currently President and Chief Financial Officer of Spring Creek Energy Company, LLC, a developer of metallurgical coal reserves in West Virginia. He has served as a Director of the Independent Oil and Gas Association of West Virginia and is the Co-Founder, past President and current Director of the Angelman Syndrome Foundation, Inc. Mr. McCullough is a graduate of the University of Southern California with a Bachelor of Arts Degree in International Economics and two Masters Degrees in Business Administration and Financial Systems Management. He is a graduate of the Northwestern University Kellogg Graduate School of Management Executive Marketing Program. Mr. McCullough serves on the Board of Directors of the ECA Foundation, Inc.

Julie M. Mork has been a Director of ECA since 1993. She is the Managing Director of the ECA Foundation, Inc., a private corporate foundation based in Denver, Colorado having a focus on youth and education. Mrs. Mork served as a founder and Secretary/Treasurer of Pacific States Gas & Oil, Inc. and EAEC. From 1989 until 1991, she served as Community Relations and Human Resources Director of EAEC. She has volunteered her time to several organizations including the Anchor Center for Blind Children where she currently serves as a member of the Advisory Board and is a past President of its Board of Directors. She also served as a member of the Cherry Creek Schools Foundation for six years. In October 2004, Mrs. Mork was elected to the National Board of College Summit, an organization dedicated to increasing the college enrollment rate of low-income students in America. Mrs. Mork received a Bachelor of Arts Degree in History from the University of California in Los Angeles and holds a Certificate in Real Estate Paralegal Training. She is the wife of John Mork and the mother of Kyle Mork.

Jerry W. Neely has been a Director of ECA since 2009. Mr. Neely is the former President, Chairman and CEO of Smith International, a public multinational oil service company. He is currently on the Board of Directors of Smith International, Avery Dennison, Security Pacific Corporation, Security Pacific National Bank, Peretec Computer, American Petroleum Institute, Petroleum Suppliers Association and the World Presidents’ Organization. He is on the University of Southern California Board of Trustees and was awarded the USC School of Business Outstanding Alumni Achievement Award. He has a Bachelor of Science Degree in Industrial Management and Business Administration from the University of Southern California.

Arthur C. Nielsen, Jr. Chairman Emeritus of the A.C. Nielsen Company, has been a Director of ECA since 1993. He was a Director of its predecessor from 1985 until 1993. He has served on the board of directors of 21 firms, some for more than a quarter of a century, including the A.C. Nielsen Company, Dun & Bradstreet, General Binding Corporation, Harris Bank, Marsh & McLennan, Motorola, Walgreens Co., Hercules, and International Executive Service Corp., and was Advisor to three U.S. Presidents. He is a Life Trustee for the American Management Association, a Director for the Chicago Foundation for Education, Life Member and President of the Economic Club of Chicago, Life Trustee for the Advertising Council, Life Trustee for the Illinois Children’s Home and Aid Society, Life Trustee for the University of Chicago, President Emeritus and Past President of the Wisconsin Alumni Research Foundation, Life Trustee for Northwestern Memorial Hospital, and Past President of the Management Executive Society. Mr. Nielsen is a graduate of the University of Wisconsin, from which he received an honorary doctorate of Human Letters Degree.

Jay S. Pifer has been a Director of ECA since 2003. Mr. Pifer served as President of West Penn Power Co., Monongahela Power Co., and The Potomac Edison Co. before becoming President of Allegheny Power where he also served as Chief Operating Officer before retiring. Under his leadership Allegheny Power became recognized as a world-class company and was ranked number one in the nation in customer satisfaction among the 30 largest electric and gas companies, ranked second in the east and in the top ten nationally by JD Power and Associates. Active in community affairs, Mr. Pifer has served on the boards of numerous organizations including, Waynesburg College, Penn State Fayette University Advisory Board, University of

Pittsburgh-Greensburg, United Way, as well as Director and Chairman of the Energy Association of Pennsylvania, Director of Ohio Electric Utilities Institute, TEAM Pennsylvania, Western Pennsylvania Conservancy, Educational Alliance of West Virginia, The Westmoreland Trust and chair of their Strategic Planning Committee, and Director of the Business Roundtable of Pennsylvania and West Virginia. He is a graduate of Penn State University and Clarion State University.

BENEFICIAL OWNERSHIP OF ECA

The following table sets forth certain information regarding (i) the share ownership of ECA by each person known to ECA to be the beneficial owner of more than 5% of the outstanding shares of common stock of ECA, (ii) the share ownership of common stock of ECA by each director, (iii) the share ownership of common stock of ECA by certain executive officers and (iv) the share ownership of common stock of ECA by all directors and executive officers as a group, in each case as of March 31, 2010. The business address of each officer and director listed below is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100, Denver, Colorado 80237.


	Beneficial Ownership
	Common Stock
	Shares		Percent

W. Gaston Caperton, III		11,680		2.24	%
Peter H. Coors(1)		8,196		1.57	%
L.B. Curtis(2)		10,750		2.06	%
John J. Dorgan(3)		4,130		*
John S. Fischer		—		—
Michael S. Fletcher		1,000		*
J. Michael Forbes		1,850		*
Thomas R. Goodwin		—		—
F.H. McCullough, III (4)		58,080		11.15	%
John Mork (5)		367,543		70.58	%
Julie M. Mork (5)		367,543		70.58	%
Kyle M. Mork (6)		5,544		1.06	%
Arthur C. Nielsen, Jr.(7)		19,880		3.82	%
George O’Malley		—		—
Jerry W. Neely		—		—
Jay S. Pifer		—		—
Donald C. Supcoe		4,583		*
All officers and directors as a group (17 persons)		493,236		94.72	%


*		Less than one percent


(1)		Includes shares held by the Peter H. Coors 2010 Grantor Retained Annuity Trust II U/A dated January 22, 2010.


(2)		Includes shares held by the Curtis Family Revocable Trust dated December 2, 1992.


(3)		Includes shares held by the Dorgan Living Trust dated April 22, 1993 as amended.


(4)		Includes 56,080 shares held by F.H. McCullough, III and Kathy McCullough as joint tenants, 880 shares held by the Katherine F. McCullough Trust, and 400 shares held by each of the Lesley McCullough Trust, the Meredith McCullough Trust and the Kristin McCullough Trust.


(5)		Includes 285,404 shares held by Shenandoah LLC, an entity wholly owned and controlled by a grantor trust created by John and Julie Mork, 74,032 shares held by John and Julie Mork as joint tenants, 2,563 shares held by Julie Mork individually, and 5,544 shares held by the Alison Mork Trust.


(6)		Includes 5,544 shares held by the Kyle Mork Trust.


(7)		Includes shares held by the Arthur C. Nielsen, Jr. Trust dated July 14, 2003.

The following table sets forth certain information regarding (1) the share ownership of ECA by each person known to ECA to be the beneficial owner of more than 5% of the outstanding shares of Class A Stock, (2) the share ownership of ECA’s Class A Stock by each Director, (3) the share ownership of ECA’s Class A Stock by certain executive officers and (4) the share ownership of ECA’s Class A Stock by all directors and executive officers as a group, in each case as of March 31, 2010. The Class A Stock differs from the Common Stock in that the Class A Stock does not have voting rights. The business address of each officer and director listed below is: c/o Energy Corporation of America, 4643 South Ulster Street, Suite 1100, Denver, Colorado 80237.


	Beneficial Ownership
	Class A Stock
	Shares		Percent

W. Gaston Caperton, III		3,420		5.23	%
Peter H. Coors (1)		4,528		6.92	%
L.B. Curtis (2)		1,180		1.81	%
John J. Dorgan (3)		3,820		5.85	%
John S. Fischer		480		*
Michael S. Fletcher (4)		2,270		3.47	%
J. Michael Forbes (4)		1,550		2.37	%
Thomas R. Goodwin		3,820		5.85	%
F.H. McCullough, III		1,180		1.81	%
John Mork (4)(5)		4,750		7.26	%
Julie M. Mork (4)(5)		4,750		7.26	%
Kyle M. Mork (4)(6)		1,969		3.01	%
Jerry W. Neely		—		—
Arthur C. Nielsen, Jr. (7)		1,180		1.81	%
George V. O’Malley (4)		1,170		1.79	%
Jay S. Pifer		1,340		2.05	%
Donald C. Supcoe (4)		2,630		4.02	%
All officers and directors as a group (17 persons)		35,287		54.00	%


*		Less than one percent


(1)		Includes shares held by the Peter H. Coors 2010 Grantor Retained Annuity Trust II U/A dated January 22, 2010.


(2)		Includes shares held by the Curtis Family Revocable Trust dated December 2, 1992.


(3)		Includes shares held by the Dorgan Living Trust dated April 22, 1993 as amended.


(4)		Includes shares included in ECA’s Incentive Stock Purchase Plan.


(5)		Includes 1,730 shares held by John and Julie Mork as joint tenants, 1,800 shares held by Julie Mork individually and 1,220 shares held by the Alison Mork Trust.


(6)		Includes 1,219 shares held by the Kyle Mork Trust.


(7)		Includes shares held by the Arthur C. Nielsen, Jr. Trust dated July 14, 2003.

EASTERN AMERICAN NATURAL GAS TRUST

In 1993, ECA sponsored the formation of the Eastern American Natural Gas Trust (NYSE: NGT), a publicly traded Delaware trust (“NGT”), to which it contributed net profits interests in Appalachian Basin natural gas properties trust units. Depositary units consisting of trust units and an interest in United States Treasury obligations (“Depositary Units”) were sold in a public offering at a price of $20.50 per Depositary Unit, resulting in gross proceeds of $120.9 million. This royalty trust holds net profits interests conveyed from the interests of ECA in 650 producing gas wells, 65 proved development well locations and associated acreage located in West Virginia and Pennsylvania. In connection with the formation of this trust, ECA agreed to drill 65 development wells over a period of five years from which NGT would be entitled to a specified percentage of the proceeds from the natural gas production. ECA completed its obligation within the stipulated period. From the formation of the trust through December 31, 2009, NGT distributed $31.02 per Depositary Unit in the aggregate. As of May 6, 2010, the closing price of each Depositary Unit as reported by the New York Stock Exchange was $22.09. The Eastern American Natural Gas Trust is expected to terminate in 2013. The historical results of operations and performance of NGT should not be relied on as an indicator of how the trust will perform.

THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act in March 2010. The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A., as trustee. Although ECA will operate all of the Producing Wells and substantially all of the PUD Wells, ECA has no ability to manage or influence the management of the trust. In addition, the Corporation Trust Company will act as Delaware trustee of the trust. The Delaware trustee will have only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.

In connection with the formation of the trust, ECA will convey to a wholly owned subsidiary a term royalty interest entitling the holder of the interest to receive 45% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PDP Royalty”) and a term royalty interest entitling such holder of the interest to receive 25% of the proceeds from the sale of the production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PUD Royalty”) in exchange for a demand note in the principal amount of $ million. The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the “Term Royalties.”

Prior to the closing of this offering, ECA and the Private Investors will convey to the trust perpetual royalty interests entitling the trust to receive, in the aggregate, 45% of the proceeds from the sale of production of natural gas attributable to the interests of ECA in the Producing Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PDP Royalty”) and ECA will convey to the trust a perpetual royalty interest entitling the trust to receive an additional 25% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PUD Royalty”) in exchange for an aggregate 4,500,000 common units constituting 25% of the trust units outstanding and 4,500,000 subordinated units constituting 25% of the trust units outstanding. The Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the “Perpetual Royalties.”

In connection with the completion of this offering, ECA’s subsidiary will convey the Term Royalties to the trust in exchange for the net proceeds of this offering, after deducting underwriting commissions and discounts and expenses, and will use the net proceeds to repay the demand note to ECA.

The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the trust at least equals amounts paid by the trustee on similar deposits, and make other short term investments with the funds distributed to the trust.

The trust will be responsible for paying all legal, accounting, tax advisory, engineering, printing costs and other administrative and out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees. These trust administrative expenses as well as the costs associated with being a publicly traded entity are anticipated to aggregate approximately $800,000 per year, although such costs could be greater or less

depending on future events that cannot be predicted. Included in the $800,000 annual estimate is an annual administrative fee of $ for the trustee and an annual administrative fee of $ for the Delaware trustee. These costs as well as those to be paid to ECA pursuant to the Administrative and Drilling Services Agreement outlined below under “— Administrative and Drilling Services Agreement,” will be deducted by the trust before distributions are made to trust unitholders.

The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.

ADMINISTRATIVE AND DRILLING SERVICES AGREEMENT

In connection with the closing of this offering, the trust will enter into an Administrative and Drilling Services Agreement with ECA that obligates the trust to pay ECA each quarter an administrative services fee for accounting, bookkeeping and informational services to be performed by ECA on behalf of the trust relating to the royalty interests. The annual fee, payable in equal quarterly installments, will total $60,000. After the completion of ECA’s drilling obligation, ECA and the trustee each may terminate the provisions of the Administrative and Drilling Services Agreement relating to the provision by ECA of administrative services at any time following delivery of notice no less than 90 days prior to the date of termination.

The Administrative and Drilling Services Agreement will also obligate ECA to use commercially reasonable efforts to drill all of the PUD Wells by March 31, 2013. In the event of delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA will grant to the trust a lien on ECA’s interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other wells which are already producing and not subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells (the “Drilling Support Lien”). The amount obtained by the trust pursuant to the Drilling Support Lien may not exceed $91 million. As ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will be proportionately reduced and the completed PUD Wells will be released from the lien.

For purposes of ECA’s drilling obligation, ECA will be credited with a full development well drilled if its working interest in the development well drilled is 100%. In the event that ECA’s working interest in a development well drilled is less than 100%, ECA will be credited with a portion of a development well in the proportion that its working interest in the development well bears to 100%. For example, if ECA’s working interest in a development well drilled by ECA in connection with fulfilling its drilling obligation to the trust is 50%, ECA will be credited with one-half of a development well for purposes of satisfying its drilling obligation in the period the development well was drilled. As a result, ECA will be required to drill more than the 52 Marcellus Shale natural gas development wells, in the aggregate, if ECA’s interest in any development well is less than 100%.

Wells drilled horizontally in the Marcellus Shale formation with a horizontal lateral distance (measured from the midpoint of the curve to the end of the lateral) of less than 2,500 feet will count as a fractional well in proportion to total lateral length divided by 2,500 feet. In the event ECA commences drilling of a PUD Well, but fails to drill beyond the mid-point of the curve, such well will not count as a fractional well. Wells with a horizontal lateral distance of greater than 2,500 feet (subject to a maximum of 3,500 feet) will count as one well plus a fractional well equal to the length drilled in excess of 2,500 (up to 3,500 feet) feet divided by 2,500 feet. Among the

Producing Wells, the average lateral length completed has been approximately 2,500 feet, with the most recent wells extending beyond the average with a maximum lateral length drilled of 3,271 feet. The reserve report was prepared based on an average lateral length of 2,000 feet for the PUD Wells.

ECA is obligated to bear all of the costs of drilling and completing the PUD Wells. ECA is required to complete and equip each development well that reasonably appears to ECA to be capable of producing gas in quantities sufficient to pay completion, equipping and operating costs. In making such decisions, ECA is required to act as a reasonably prudent operator in the AMI under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. See “The Underlying Properties — Sale and Abandonment of Underlying Properties.”

ECA will covenant and agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the Marcellus Shale formation on lease acreage included within the AMI for its own account until such time as ECA has met its commitment to drill the PUD Wells. Once ECA has completed its drilling obligation, the trustee will be required to release the Drilling Support Lien in full. Upon the trustee’s release of the Drilling Support Lien, ECA will further agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well on the lease acreage that is located within 500 feet of any PUD Well or Producing Well in the Marcellus Shale formation.

TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS

ECA will create the royalty interests through conveyances to the trust of royalty interests carved from their working interests in specified gas properties in Pennsylvania. The PDP Royalty Interest will entitle the trust to receive 90% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest will entitle the trust to receive 50% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of future production of natural gas attributable to ECA’s interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter.

The amount of trust revenues and cash distributions to trust unitholders will depend on:


	•	the timing of initial production from the PUD Wells;

	•	natural gas prices received;

	•	the volume and Btu rating of natural gas produced and sold;

	•	post-production costs and any applicable taxes;


	•	the reimbursement by the trust, if any, of ECA’s costs associated with establishing the floor price contracts to be transferred to the trust; and


	•	administrative expenses of the trust and expenses incurred as a result of being a publicly traded entity.

ECA has calculated quarterly target levels of cash distributions for the life of the trust. Such target distribution levels are set forth on Annex B to this prospectus. The target distributions were prepared by ECA on an accrual basis based on volumes, pricing and other assumptions that are described below in “— Significant assumptions used to prepare the target distributions.” As used herein, accrual basis means ECA will pay to the trust each quarter an amount equal to the estimated proceeds of production from the trust properties during the calendar quarter most recently ended before the distribution (after deducting post-production costs and any applicable taxes), regardless of whether such amounts have actually been received by ECA from the purchaser of the natural gas produced.

The amount of the quarterly distributions may fluctuate from quarter to quarter, depending on the proceeds received by the trust, among other factors. Annex B reflects that while target distributions increase as ECA completes its drilling obligations and production attributable to the trust increases, over time these target distributions decline as a result of the depletion of the reserves in the Underlying Properties. These “target distributions” do not represent the actual distributions you should expect to receive with respect to your common units. Rather, the trust has established the target distributions in part to calculate the subordination and incentive thresholds described in more detail below.

on the common units. Each applicable quarterly subordination threshold is equal to 80% of the target distribution level for the corresponding quarter as reflected on Annex B. In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations on the Underlying Properties in an efficient and cost-effective manner, ECA will be entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 150% of the subordination threshold for such quarter (which is 120% of the target distribution for such quarter). ECA’s right to receive the incentive distributions will terminate upon the expiration of the subordination period.

ECA has incurred costs of approximately $5 million in establishing the floor price contracts to be transferred to the trust. ECA will be entitled to reimbursement for these expenditures plus interest accrued at 10% per annum only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the trust unitholders.

The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the hedging contracts it has established for the benefit of the trust. The trust currently expects that ECA will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units would convert into common units on or before March 31, 2014. In the event of delays, ECA will have until March 31, 2014 to drill all the PUD Wells, in which event the subordinated units would convert into common units on or before March 31, 2015.


	Subordination		Target		Incentive
Period	Threshold		Distribution		Threshold
			(per unit)

2010:
Second Quarter	$	0.217	$	0.271	$	0.326
Third Quarter		0.298		0.372		0.447
Fourth Quarter		0.426		0.532		0.639
2011:
First Quarter		0.413		0.516		0.619
Second Quarter		0.418		0.523		0.627
Third Quarter		0.520		0.650		0.780
Fourth Quarter		0.544		0.680		0.815
2012:
First Quarter		0.562		0.702		0.843
Second Quarter		0.595		0.744		0.893
Third Quarter		0.607		0.759		0.911
Fourth Quarter		0.688		0.859		1.031
2013:
First Quarter	$	0.773	$	0.967	$	1.160
Second Quarter		0.771		0.964		1.157
Third Quarter		0.717		0.896		1.075
Fourth Quarter		0.674		0.842		1.010
2014:
First Quarter		0.623		0.779		0.935
Second Quarter		0.601		0.751		0.902
Third Quarter		0.583		0.728		0.874
Fourth Quarter		0.561		0.701		0.841
2015:
First Quarter		0.530		0.663		0.795

ECA does not as a matter of course make public projections as to future sales, earnings, or other results. However, the management of ECA has prepared the projected operational and financial information set forth below in order to present the target distributions attributable to the natural gas sales volumes reflected in Ryder Scott’s reserve report attached hereto as Annex A. The target distributions, in the view of ECA’s management, were prepared on a reasonable basis based on the assumptions outlined in “— Significant assumptions used to prepare the target distributions”.

The projections outlined below are not fact and should not be relied upon as being necessarily indicative of future results. Neither ECA nor the trust undertakes any obligation to update the financial forecast to reflect events or circumstances after the date of this prospectus and readers of this prospectus are cautioned not to place undue reliance on the projected financial information.

Neither ECA’s independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information.

The projections and assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of ECA and the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in natural gas prices production volumes. See “— Sensitivity of target distributions to natural gas prices and volumes” which shows estimated effects to cash distributions through March 31, 2011 from hypothetical changes in natural gas prices as well as hypothetical changes in production volumes. As a result of typical production declines for natural gas properties, production estimates generally decrease from year to year. However, the production estimates included in the table below reflect that these declines are expected to be offset by additional production from PUD Wells as they are turned in line. The timing of the completion of, and the amount of production attributable to the PUD Wells, are substantially dependent on ECA executing its drilling plans with respect to the drilling and completion of the PUD Wells in a manner substantially similar to those underlying the assumptions used in establishing these target distributions. Please see “Risk Factors” for risks relating to the timing of drilling and amount of production attributable to the PUD Wells. As a result of these factors, the target distributions shown in the tables below are not necessarily indicative of distributions for future years. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of trust unitholders’ original investment. See “Risk Factors — The natural gas reserves attributable to the Underlying Properties of the trust are depleting assets and production from those reserves will diminish over time. Furthermore, the trust is generally precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production.”

The table below presents the calculation of the target distributions for each quarter through and including the quarter ending June 30, 2011.


	Quarters Ending
	June 30,			September 30,			December 31,			March 31,			June 30,
	2010			2010			2010			2011			2011
	(In thousands, except well number, volumetric and per unit data)

Number of wells producing at quarter end		8			17			22			25			31
*Estimated Production from Trust Properties*
Natural Gas PDP Sales Volumes (MMcf)		879			1,190			1,265			1,066			962
Natural Gas PUD Sales Volumes (MMcf)		—			81			514			553			769
Total Sales Volumes (MMcf)		879			1,271			1,779			1,619			1,731
Daily Sales Volumes (Mcf/d)		9,664			13,814			19,336			17,988			19,020
*Commodity Prices and Hedging Positions* (1)
Assumed NYMEX Price ($/MMBtu) (2)	$	4.58		$	4.75		$	5.27		$	5.81		$	5.34
Assumed Price ($/Mcf)		4.72			4.89			5.42			5.98			5.50
Realized Unhedged Price after Basis Differential ($/Mcf)		4.88			5.04			5.58			6.13			5.65
Daily Hedged Volumes (MMcf/d) (3)		7.3			7.3			9.7			9.0			9.5
Percent of Total Volumes Swapped		75	%		53	%		38	%		40	%		38	%
Swap Price ($/MMBtu)	$	6.75		$	6.75		$	6.75		$	6.75		$	6.75
Percent of Total Volumes Floored		—			—			12	%		10	%		12	%
Floor Price ($/MMBtu)	$	—		$	—		$	5.00		$	5.00		$	5.00
Realized Hedged Weighted Average Price ($/Mcf) (3)	$	6.55		$	6.13		$	6.15		$	6.53		$	6.21
*Cash available for distribution*
Gas Sales Revenues	$	4,288		$	6,408		$	9,923		$	9,932		$	9,786
Swap and Floor Hedge Revenues		1,476			1,381			1,021			635			960

Total Revenues	$	5,764		$	7,788		$	10,944		$	10,566		$	10,746

Post-Production Services Fee (4)	$	471		$	681		$	953		$	867		$	927
Trust Expenses		200			200			200			200			201
Franchise Taxes		207			207			211			211			211

Cash Available for Distribution	$	4,885		$	6,701		$	9,581		$	9,288		$	9,407

Trust Units Outstanding		18,000			18,000			18,000			18,000			18,000
Target Distribution Per Trust Unit	$	0.271		$	0.372		$	0.532		$	0.516		$	0.523
Subordination Threshold Per Trust Unit	$	0.217		$	0.298		$	0.426		$	0.413		$	0.418
Incentive Threshold Per Trust Unit	$	0.326		$	0.447		$	0.639		$	0.619		$	0.627


(1)		For a more detailed description of the natural gas hedging contracts established for the benefit of the trust, please see “Description of the Royalty Interests.”

(2)		Based on NYMEX forward pricing as of March 11, 2010. Assumed price per Mcf calculated based on an assumed conversion rate of 1.03 MMBtu per Mcf.


(3)		Adjusted for an assumed basis differential of $0.15 per MMBtu.

(4)		Consists of a fee of $0.52 per MMBtu.

SIGNIFICANT ASSUMPTIONS USED TO PREPARE THE TARGET DISTRIBUTIONS

In preparing the target distributions and subordination and incentive threshold tables above and sensitivity tables below, the revenues and expenses of the trust were calculated based on the terms of the conveyances creating the trust’s royalty interests using the following assumptions and those set forth above under “Target Distributions and Subordination and Incentive Thresholds.” These calculations are described under “Description of the Royalty Interests.”

Production estimates. Production estimates for each of the quarters during the life of the trust are based on the reserve report. The estimates of reserves and production relating to the Underlying Properties and the royalty interests included in the reserve report have been made in accordance with the SEC’s new rules for reserve reporting. Production attributable to the royalty interests from the Underlying Properties for the twelve months ending June 30, 2011 is estimated to be 6,400 MMcfe of natural gas. The estimated production in the forecast period gives effect to the drilling and completion by ECA of three PUD Wells in the third quarter of 2010; five PUD Wells in the fourth quarter of 2010; three PUD Wells in the first quarter of 2011; six PUD Wells in the second quarter of 2011; and the completion by ECA of its drilling obligation to the trust by March 31, 2013. See “— Natural gas prices” below for a description of changes in production due to price variations. Differing levels of production will result in different levels of distributions and cash returns.

Natural gas prices. The hypothetical natural gas prices utilized for purposes of preparing the target distributions are based on estimated market prices for natural gas based on NYMEX forward pricing as of March 11, 2010 for the thirty-six month period ending March 31, 2013 and increased thereafter by a 2.5% annual escalator (as adjusted for a basis differential of $0.15 per MMBtu), capped at $9.00 per MMBtu starting in 2025. The assumed price per Mcf is calculated based on an assumed conversion rate of 1.03 MMBtu per Mcf. Actual MMBtu per Mcf may differ as it will be based on the actual heat content of the gas produced. These prices estimate market prices of $4.58 per MMBtu for the quarter ending June 30, 2010, $4.75 per MMBtu for the quarter ending September 30, 2010, $5.27 per MMBtu for the quarter ending December 31, 2010, $5.81 per MMBtu for the quarter ending March 31, 2011 and $5.34 per MMBtu for the quarter ending June 30, 2011. We have assumed that 50% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged from April 1, 2010 to March 31, 2014. These floor price contracts will be transferred to the trust by ECA, while ECA will enter into back-to-back swap agreements with the trust, and ECA will be entitled to recoup the costs of establishing the floor price contracts if cash available for distribution by the trust reaches certain levels. The average realized sales price for gas gathered and sold on ECA’s Greene County Gathering System (prior to any post-production costs) for the twelve months ended June 30, 2009 was $6.85 per MMBtu. This was approximately $0.46 above the average closing NYMEX natural gas futures contract prices for the same period. However, if previously occurring location, quality and other differentials change in the future, there may be more significant differences between the natural gas price received and the NYMEX price than the assumed $0.15 per MMBtu differential used in these estimations. In addition, the market price of natural gas is generally higher in the winter months than during the other months of the year due to increased demand for natural gas for heating purposes during the winter season. The price of natural gas fluctuates based on levels of supply and demand at any given time. The adjustments to realized natural gas prices applied in the tables above are based upon an analysis by ECA of the historic price differentials for production from the Underlying Properties with consideration given to quality and transportation and marketing costs that may affect these differentials for the forecast period. There is no

assurance that these assumed differentials will be the same during the periods presented in the tables above.

If natural gas prices decline, the operators of producing oil and gas properties may elect to reduce or completely suspend production. ECA is required under the applicable conveyance to act as a reasonably prudent operator with respect to the Underlying Properties under the same or similar circumstances as it would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. No adjustments have been made to estimated production in the tables above to reflect potential reductions or suspensions of production.

Administrative expense. Trust administrative expense per year is expected to be approximately $800,000 per year, although such costs could be greater or less depending on future events that cannot be predicted. Included in the $800,000 annual estimate, among other miscellaneous items, is an annual administrative fee of $ for the trustee and an annual administrative fee of $ for the Delaware trustee. In addition, the trust will pay an annual administrative fee to ECA pursuant to the Administrative and Drilling Services Agreement, which fee will total $60,000 per year which will remain flat for the life of the trust. The balance ($740,000) is escalated at 2.5% annually starting in the second quarter of 2011. The trust will also pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as the Delaware trustee’s acceptance fee in the amount of $ . These costs will be deducted by the trust before distributions are made to trust unitholders.

Tax treatment of royalty interests. For federal income tax purposes, the Term PDP Royalty will be and the Term PUD Royalty should be treated as debt instruments. Accordingly, the Term Royalties will be subject to the original issue discount, or OID, rules of the Internal Revenue Code which require that payments made to the trust with respect to the Term Royalties will be treated first as consisting of a payment of interest to the extent of interest deemed accrued under the OID rules at the applicable federal rate and the excess, if any, will be treated as a payment of principal (which is non-taxable). For federal income tax purposes, the Perpetual PDP Royalties will be, and the Perpetual PUD Royalties should be, treated as mineral royalty interests, which give rise to ordinary income subject to depletion.

Timing of actual cash distributions. The payments by ECA in respect of the royalty interests will be made by ECA on an accrual basis. As used herein, accrual basis means ECA will pay to the trust each calendar quarter an amount equal to the proceeds of estimated production from the trust properties during the calendar quarter most recently ended before the distribution.

Post-production costs. The Post-Production Services Fee of $0.52 per MMBtu is held flat for the life of the trust. The actual Post-Production Services Fee of $0.52 per MMBtu may differ once ECA’s drilling obligation is fulfilled. ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System after the completion of the drilling period, provided the resulting charge does not exceed the prevailing charges in the area for similar services.

Estimated total reserves and quarterly production volumes are net of an assumed 5% natural gas fuel compression charge and line loss, which percentage is based off of ECA’s historical experience in Greene County, Pennsylvania. In the event that ECA chooses to use electrical compression in the future, costs would differ. Actual compressor fuel charges and line loss will be allocated to the trust’s interests and may differ from the 5% assumed in the reserve report. No other post-production costs were contemplated in the target distributions but the trust would be responsible for any new post-production costs.

Applicable taxes. There are currently no taxes in Pennsylvania related to the production or severance of oil and natural gas in Pennsylvania. Pennsylvania has not historically imposed any such taxes, but legislation is pending in the Pennsylvania Senate Finance and the House Energy and Environmental Resources Committees that provides for a severance tax of 5% on the value of the natural gas at the wellhead plus $0.047 per thousand cubic feet of natural gas severed. See “Risk Factors — Recently proposed severance taxes in Pennsylvania could materially increase the post-production costs that are borne by the trust.” In addition, the trust will be required to pay Pennsylvania franchise tax on its capital stock value, as determined pursuant to the statute and apportioned to Pennsylvania. The current tax rate of 0.289% is currently scheduled to be reduced to 0.189% in 2012 and 0.089% in 2013 and to be completely phased out in 2014. This schedule may be altered and the taxes left in place subsequent to the General Assembly in its annual budget process.

Hedge cost reimbursement. To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period, ECA will be entitled to receive 50% of such cash as incentive distributions and 50% of such cash as recoupment of its costs for establishing the hedge contracts until it has recouped approximately $5 million. The incentive distributions and the hedging reimbursement terminate upon completion of the subordination period.

SENSITIVITY OF TARGET DISTRIBUTIONS TO CHANGES IN NATURAL GAS PRICES AND VOLUMES

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for natural gas sold, the volumes of gas produced and, to some degree, variations in property and production taxes, if any, and post-production costs. The following tables demonstrate the projected effect that hypothetical changes in the estimated gas production for the forecast period ending June 30, 2011 as reflected in the reserve report and the impact that hypothetical fluctuations in assumed realized gas prices could have on cash distributions to the trust unitholders.

These tables set forth the sensitivity of annual cash distributions per trust unit for the forecast period ending June 30, 2011 based upon (1) the assumption that a total of 18,000,000 trust units are issued and outstanding after the closing of the offering made hereby; (2) an assumed initial public offering price of $ per common unit; (3) various realizations of production levels estimated in the reserve report; (4) various hypothetical realized gas prices; (5) the impact of the natural gas hedging contracts owned by the trust that entitle the trust to receive payments from the counterparties to such contracts, including ECA, in the event that natural gas prices are lower than the floor prices specified in the contracts; (6) assumptions regarding applicable taxes and post-production costs; (7) assumptions regarding administrative expenses; and (8) other assumptions described below under “— Significant Assumptions Used to Prepare the Target Distributions.” The hypothetical realized prices of gas production shown have been chosen solely for illustrative purposes.

The tables give effect to the subordination and incentive distribution features that are contained in the terms of the trust. For a description of the way in which those features would impact trust unitholders’ distributions, please see “Target Distributions and Subordination and Incentive Thresholds.”

The below tables are not a projection or forecast of the actual or estimated results from an investment in the common units. The purpose of these tables is to illustrate the sensitivity of cash distributions to changes in production levels and the price of natural gas. There is no assurance that the hypothetical assumptions described below will actually occur or that

production levels and the price of natural gas will not change by amounts different from those shown in the tables.

The trust’s natural gas hedging contracts will be in effect only through March 31, 2014, and thus there is likely to be greater fluctuation in cash distributions resulting from fluctuations in realized natural gas prices in periods subsequent to the expiration of those contracts. See “Risk factors” for a discussion of various items that could impact production levels and the price of natural gas.

These distributions are sensitized to both assumed NYMEX natural gas prices as well as the assumed production from the trust properties. The quarterly distributions in the tables below are based on assumptions outlined in “— Significant Assumptions Used to Prepare the Target Distributions.” In the tables set forth below, we have provided examples of possible distributions for the quarters ending June 30, 2010, September 30, 2010, December 31, 2010 and March 31, 2011 based on various NYMEX pricing and production assumptions.

For scenarios in these tables which involve lower NYMEX gas prices and production volumes, the quarterly distribution per unit does not fall below the subordination threshold because either the per unit cash available for distribution to trust unitholders was at or above the subordination threshold or the cash flows to the subordinated units support the distributions to the common units. For scenarios in these tables with higher gas prices and production volumes, the quarterly distribution per unit does not exceed the incentive threshold either because the per unit cash available for distribution to trust unitholders was at or below the incentive threshold or because the per unit cash available for distribution in excess of the incentive threshold is used to reimburse ECA for its costs of approximately $5 million plus interest accrued at 10% per annum for establishing the natural gas hedging contracts transferred to the trust.

For each table, the assumed NYMEX gas price per MMBtu used to estimate quarterly distributions is also the assumed NYMEX gas price for all previous quarters. In order for a trust unitholder to receive a distribution in excess of the incentive threshold, the hedge cost must be repaid to ECA in full.

THE UNDERLYING PROPERTIES

The Underlying Properties consist of the working interests owned by ECA and the Private Investors in the Marcellus Shale formation in Greene County, Pennsylvania arising under leases and farmout agreements related to properties from which the PDP Royalty Interest and the PUD Royalty Interest will be conveyed. There are in excess of 100 potential drilling locations for the PUD Wells within the AMI. As of March 31, 2010 and after giving effect to the conveyance of the PDP Royalty Interest and the PUD Royalty Interest, the total gas reserves attributable to the trust interests were 104.6 Bcf. This amount includes 72.4 Bcf attributable to the PUD Royalty Interest and 32.2 Bcf attributable to the PDP Royalty Interest. ECA is currently the operator of all of the wells subject to the PDP Royalty Interest. ECA has an average working interest of approximately 93% in the wells subject to the PDP Royalty Interest. Two third parties hold an approximate 50% and 35% working interest in two Producing Wells. ECA holds the remaining approximate 50% and 65% working interest in such wells. The reserves attributable to the trust’s royalty interests include the reserves that are expected to be produced from the Marcellus Shale formation during the 20-year period in which the trust owns the royalty interests as well as the residual interest in the reserves that the trust will sell on or shortly following the Termination Date.

As of March 31, 2010, the Underlying Properties include eight gross (7.65 net) productive gas wells which encompass approximately 493 gross (474 net) productive acres. Immediately following the completion and initial production of the final six Producing Wells (currently classified as proved behind pipe), the Underlying Properties will include 14 gross (13.15 net) productive gas wells encompassing 819 gross (769 net) productive acres. Currently, the Underlying Properties include approximately 8,480 gross (9,300 net) undeveloped acres.

HISTORICAL RESULTS FROM THE PRODUCING WELLS

The following table provides revenues and direct operating expenses relating to the Producing Wells for the six months ended December 31, 2009 derived from the Underlying Properties’ audited statement of revenues and direct operating expenses included elsewhere in this prospectus. During the six months ended December 31, 2009, only four of the 14 Producing Wells were completed. As a result, the information in the table set forth below will not be comparable to the trust’s results going forward as ECA completes additional Producing Wells. The information in the table below does not reflect the formation of the trust or the conveyance of the PDP Royalty Interest to the trust. The selected financial data presented below should be read in conjunction with the audited statement of revenues and direct operating expenses of the Underlying Properties, the related notes and “Discussion and Analysis of Historical Results from the Producing Wells” included elsewhere in this prospectus and the discussion of ECA’s business and related Management’s Discussion and Analysis of Financial Condition and Results of Operations of Energy Corporation of America set forth in “Information about Energy Corporation of America.”


	Six Months Ended
Historical Results	December 31, 2009
	(Dollars in thousands, except volumetric data)

Natural gas sales volumes (Mcf) (unaudited)		841,261
Gross sales price per Mcf (unaudited)	$	4.31

Revenues from gas sales	$	3,623
Direct operating expenses:
Production and property taxes		—
Production expenses		24
Marketing fee (1)		132
Gathering and transportation charges		458

Total		614

Excess of revenues over direct operating expenses	$	3,009


(1)		A wholly-owned subsidiary of ECA markets the production from the Underlying Properties. Historically, such subsidiary has charged a marketing fee for its services; however, the trust will not be charged a marketing fee by ECA for marketing production.

NATURAL GAS SALES PRICES AND PRODUCTION COSTS

The following table sets forth the production, the average sales price per Mcf and the production costs for the six-month period ended December 31, 2009 for the Producing Wells on a historical basis and for the six months ended on December 31, 2009 for the royalty interests on a pro forma basis.


	Historical for		Pro forma for
	Producing Wells		Royalty Interest (1)
	Six Months Ended		Six Months Ended
	December 31,		December 31,
	2009		2009

Production (MMcf)		841		757
Average net sales price per Mcf:
Average gross sales price per Mcf	$	4.31	$	4.31
Gathering and transportation charges (Mcf)		0.54		0.54
Average sales price (2)		3.60		3.76
Average production cost per Mcf (3)	$	0.03		—


(1)		Pro forma figures are calculated as if the conveyances were in effect for the period indicated.

(2)		Average sales price generally represents the realized price of gas which is net of post-production costs and applicable taxes, if any.

(3)		Production costs include lease operating costs.

DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS FROM THE PRODUCING WELLS

During the six months ended December 31, 2009, ECA drilled and completed four horizontal wells in the Marcellus Shale formation in Greene County, Pennsylvania. The first of these wells began producing and selling natural gas on July 17, 2009. One of the remaining three wells was put into production during each of the months of August, September and October 2009. These wells were drilled with an average lateral length of 2,000 feet and completed with an average of 7.5 fracture stimulations per well. Aggregate monthly production ranged from a low of 35,690 Mcf during the month of July 2009 to a high of 192,445 Mcf during the month of November 2009 and ended the period with all four wells in line and producing an average of more than 5,600 Mcf per day in aggregate. Total volumes produced and sold during the period, from the four wells were 841,261 Mcf.

The average gross sales price received for gas produced during the six months ended December 31, 2009 was $4.31 per Mcf, before deduction of any post-production costs or operating expenses. Gross sales prices received ranged from a low of $3.06 per Mcf during the month of September 2009 to a high of $5.34 per Mcf during the month of December 2009. Post-production costs, which consisted of a gathering fee of $0.54 per Mcf and a marketing fee of $0.16 per Mcf, totaled $590,439 for the period. Operating expenses averaged approximately $1,333 per well month during the period. Revenues less direct operating expenses were approximately $3.01 million for the six months ended December 31, 2009.

THE UNDERLYING PUD PROPERTIES

At the completion of this offering, the underlying PUD properties will consist of all of the working interests in proved undeveloped gas properties in the AMI held by ECA. The interests of ECA in the gas properties to which the underlying PUD properties relate consist of working interests of approximately 100%. The conveyance related to the PUD Royalty Interest, however, provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are only burdened by interests that in total would not exceed 12.5% of the revenues

from such properties, regardless of whether the other interest owners are actually entitled to a greater percentage of revenues from such properties. The AMI is located in Greene County, Pennsylvania, which is in southwestern Pennsylvania and consists of approximately 121 square miles.

The PUD Royalty Interest will entitle the trust to receive an undivided 50% interest in the proceeds from the sale of future production of natural gas resulting from the drilling of the PUD Wells. Once ECA has drilled all of the PUD Wells, the trustee will be required to release the Drilling Support Lien.

ECA will covenant and agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the Marcellus Shale formation on the lease acreage included within the AMI described above for its own account until such time as ECA has met its commitment to drill the PUD Wells. Upon the trustee’s release of the Drilling Support Lien, ECA will further agree not to drill and complete, and will not permit any other person within its control to drill and complete, any well in the Marcellus Shale formation on the lease acreage that is located within 500 feet of any PUD or Producing Well.

ECA, in the conveyance documents for the PUD Royalty Interest, will expressly except and reserve all right, title and interest in and to any well and appurtenant production facilities not expressly conveyed to the trust. The PDP Royalty Interest is included within the AMI and those properties will remain subject to the terms and conditions of the PDP Royalty Interest conveyance documents.

The PUD Royalty Interest conveyances shall further provide that the PUD Royalty Interest of the trust will be applicable to any additional acreage leased or acquired by any other means by ECA within the AMI until the drilling obligation of ECA to the trust is met. No assurance can be given, however, that any development well will produce in commercial quantities or that the characteristics of any development well will match the characteristics of ECA’s existing wells or ECA’s historical drilling success rate. ECA operates all of the Producing Wells and will agree to operate not less than 90% of the PUD Wells during the subordination period.

NATURAL GAS RESERVES

Ryder Scott estimated natural gas reserves attributable to the Underlying Properties as of March 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

Proved reserves of Underlying Properties and royalty interests. The following table, effective as of March 31, 2010, contains certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to both the Underlying Properties and the royalty interests, in each case derived from the reserve report. The reserve report was prepared by Ryder Scott in accordance with criteria established by the SEC. In accordance with the SEC’s new rules, the reserves presented below were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from April 1, 2009 through March 1, 2010, without giving effect to any derivative transactions, and were held constant for the life of the properties. This yielded a price for natural gas of $3.984 per MMBtu. Proved reserve quantities attributable to the royalty interests are calculated by multiplying the gross reserves for each property by the royalty interest assigned to the trust in each property. The net revenues attributable to the trust’s reserves are net of the trust’s obligation to reimburse ECA for the post-production costs. The reserves related to the Underlying Properties include all of the proved reserves expected to be economically produced from the Marcellus Shale formation during the life of the properties. The reserves and revenues attributable to the trust’s interests include only the reserves attributable to the Underlying Properties that are expected to be produced within the 20-year period in which the trust owns the royalty interest as well as the 50% residual interest in the reserves that the trust will own on the Termination Date. A summary of the reserve report is included as Annex A to this prospectus.


	Proved Gas				Discounted
	Reserves		Estimated Future		Estimated Future
Proved reserves	(Bcfe)		Net Revenues		Net Revenues (1)
	(Dollars in thousands)

Underlying Properties		193.8	$	507,289	$	168,687

Royalty Interests:
PDP Royalty Interest (90%) (2)		32.2	$	119,757	$	67,161
PUD Royalty Interest (50%)		72.4	$	269,175	$	133,109

Total		104.6	$	388,932	$	200,270


(1)		The present values of future net revenues for the Underlying Properties and the royalty interests were determined using a discount rate of 10% per annum.

(2)		Includes reserves currently behind pipe in existing wells which are in the process of being completed.

Information concerning historical changes in net proved reserves attributable to the Underlying Properties, and the calculation of the standardized measure of discounted future net revenues related thereto, is contained in the unaudited supplemental information contained elsewhere in this prospectus. ECA has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

THE RESERVE REPORT

Technologies. The reserve report was prepared using decline curve analysis to determine the reserves of individual Producing Wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the Producing Wells, which cover a wide area of the AMI, further supports proved undeveloped classification.

Also, a 3-D seismic survey was shot and interpreted across substantially all of the AMI and has been used to confirm the consistency of important reservoir properties throughout the AMI. Electric logs and other geologic and engineering data gathered from proved developed wells and

vertical Marcellus Shale wells ECA has previously drilled across the AMI further support the consistency of the Marcellus Shale reservoir throughout the AMI. Finally, ECA regularly trades geologic, engineering, and operations data with other operators in the area surrounding the AMI. This technical and production data further supports the consistency of the Marcellus Shale in and around the AMI.

Internal Controls. Ryder Scott, the independent petroleum engineering consultant, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, all of the proved reserve information in this registration statement. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Society of Petroleum Engineers’ Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information. ECA’s internal control over its reserve reporting process is designed to result in accurate and reliable estimates in compliance with applicable regulations and guidance. Internal reserve preparation is performed by staff reservoir engineers and geoscientists before review by the Reservoir Engineering Manager and finally the Vice President of Eastern Operations. These individuals consult regularly with Ryder Scott during the reserve estimation process to review properties, assumptions, and any new data available. Additionally, ECA’s senior management reviewed and approved all Ryder Scott reserve reports contained herein.

ECA’s Vice President of Eastern Operations is the primary technical person responsible for overseeing the reserve reporting process. This individual has a Bachelor of Science degree in Chemical Engineering with Masters of Petroleum Engineering coursework along with a Masters 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.

Material Changes. The reserve report for Underlying Properties was prepared for the first time as of December 31, 2009. At this time, four of the wells were classified as proved developed wells, three wells were classified as proved behind pipe, with the remaining 59 wells to be drilled classified as PUD wells. During the three months prior to the March 31, 2010 report, ECA completed the three proved behind pipe wells along with one proved undeveloped well, all of which were converted to proved developed wells. Additionally, ECA was preparing for completion six wells, which were converted from proved undeveloped to proved behind pipe wells. As a part of the trust agreement, ECA has an obligation to drill all 52 PUD Wells by March 31, 2013, and no later than March 31, 2014 if delays occur. Therefore, upon its completion of its drilling obligation, ECA anticipates that all proved undeveloped reserves should be converted to proved developed reserves.

During the three month period from December 31, 2009 to March 31, 2010, ECA spent $6,750,000 converting four wells from proved behind pipe or proved undeveloped to proved developed reserves, and ECA spent $4,295,000 converting six proved undeveloped wells to proved behind pipe wells.

During the three month period from December 31, 2009 to March 31 2010, ECA drilled four productive development wells and zero dry wells. Also during this time, ECA began preparation for the completion process for the wells currently classified as proved behind pipe reserves.

As of March 31, 2010, ECA was preparing for the completion of the final six proved developed wells on the Underlying Properties, which are currently classified as proved behind pipe wells within the reserve report. These wells are all located on the same pad drilling location and will be completed at the same time.

SALE AND ABANDONMENT OF UNDERLYING PROPERTIES

ECA and any transferee will have the right to abandon its interest in any well or property comprising a portion of 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 commercially paying quantities, ECA is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as a burden affecting such property.

After completion of its drilling obligation, ECA generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the royalty interests, without the consent of the trust unitholders. In addition, ECA may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust not to exceed $5.0 million during any 12-month period. These releases will be made only in connection with a sale by ECA of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests. ECA operates all of the Producing Wells and will operate not less than 90% of the PUD Wells during the subordination period. Any net sales proceeds paid to the trust are distributable to trust unitholders for the quarter in which they are received. ECA has not identified for sale any of the Underlying Properties.

MARKETING AND POST-PRODUCTION SERVICES

Pursuant to the terms of the conveyances creating the royalty interests, ECA will have the responsibility to market, or cause to be marketed, the natural gas production related to the Underlying Properties. The terms of the conveyances creating the royalty interests do not permit ECA to charge any marketing fee when determining the proceeds upon which the royalty payments will be calculated. As a result, the proceeds to the trust from the sales of natural gas production from the Underlying Properties will be determined based on the same price (net of post-production costs) that ECA receives for natural gas production attributable to ECA’s remaining interest in the Underlying Properties.

A wholly owned subsidiary of ECA markets the majority of ECA’s operated production and markets substantially all of the gas produced from the Underlying Properties. Such subsidiary enters into gas sales arrangements with large aggregators of supply and these arrangements may be on a month-to-month basis or may be for a term of up to one year or longer. The natural gas is sold at a market price and subsequently any applicable post-production costs will be deducted. The trust will not be charged any fee for marketing by ECA. The primary aggregators of supply with whom ECA currently does business in the AMI are BP Energy Company, Equitable Energy LLC, South Jersey Resource Group and Hess Corporation. In addition to providing marketing services, ECA’s subsidiary purchases all of the production from the Underlying Properties and those sales account for 100% of the revenue from the Underlying Properties.

Substantially all of the production from the Producing Wells and the PUD Wells will be gathered by ECA’s Greene County Gathering System. Following this offering, the trust will pay the initial Post-Production Services Fee of $0.52 per MMBtu for use of this system, including ECA’s costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee is fixed until ECA’s drilling obligation is satisfied; thereafter, ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System made after the completion of the drilling period, provided the resulting charge does not exceed the prevailing charges in the area for similar services. This fee does not include the cost of fuel used

in the compression process or equivalent electricity charges when electric compressors are used. The reserve report assumes a 5% retainage for compression fuel and line loss on the Greene County Gathering System. This percentage represents current operating conditions, though such level may fluctuate going forward. The trust’s cash available for distribution will be reduced by ECA’s deductions for these post-production services.

There are currently no third-party post-production costs, but ECA or one of its affiliates may enter into arrangements with third parties to provide gathering, transportation, processing and other reasonable post-production services, including transportation on downstream interstate pipelines. Such additional post-production costs will be expressed as either (1) a cost per MMBtu or Mcf or (2) a percentage of the gross production from a well. To the extent that post-production costs are expressed as a cost per MMBtu or Mcf, such costs may be deducted by the ultimate purchaser of the natural gas prior to payment being made to ECA or its marketing affiliate for such production. At other times, ECA or its marketing affiliate will make payments directly to the third parties providing such post-production services. In either instance, the trust’s cash available for distribution will be reduced by the costs paid by ECA for such post-production services provided by third parties. If the post-production costs are expressed as a percentage of the gross production from a well, then the volume of production from that well actually available for sale is less the applicable percentage charged, and as a result the reserves associated with that well that are attributable to the royalty interest are reduced accordingly.

The post-production costs for natural gas production from the Producing Wells were $0.52 per MMBtu as of December 31, 2009. After giving effect to the drilling and completion of the PUD Wells, ECA anticipates that the Post-Production Services Fee will be the only such cost, yielding the weighted average post-production costs for production attributable to the trust’s royalty interest of approximately $0.52 per MMBtu.

Regardless of whether the post-production costs are based upon (1) a cost per MMBtu or Mcf or (2) a percentage of gross production from a well, such costs may increase or decrease in the future. The post-production costs attributable to third party arrangements may be costs established by arms-length negotiations or pursuant to a state or federal regulatory proceeding. ECA will be permitted to deduct from the proceeds available to the trust other post-production costs necessary to make the natural gas from the Underlying Properties marketable, so long as such costs do not materially exceed the charges prevailing in the area for similar services.

ECA expects to enter into similar gas supply arrangements and post-production service arrangements for the gas to be produced from the underlying PUD properties. Any new gas supply arrangements or those entered into for providing post-production services, will be utilized in determining the proceeds for the Underlying Properties.

TITLE TO PROPERTIES

The Underlying Properties are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect ECA’s rights to production and the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the royalty interests.

ECA acquired its interests in the Underlying Properties through a variety of means, including through the acquisition of oil and gas leases by ECA directly from the mineral owner, through assignments of oil and gas leases to ECA by the lessee who originally obtained the leases from the mineral owner, through farmout agreements that grant ECA the right to earn interests in the

properties covered by such agreements by drilling wells, and through acquisitions of other oil and gas interests by ECA.

ECA’s interests in the gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:


	•	royalties and other burdens, express and implied, under gas leases;

	•	production payments and similar interests and other burdens created by ECA or its predecessors in title;

	•	a variety of contractual obligations arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

	•	pooling, unitization and communitization agreements, declarations and orders;

	•	easements, restrictions, rights-of-way and other matters that commonly affect property;

	•	conventional rights of reassignment that obligate ECA to reassign all or part of a property to a third party if ECA intends to release or abandon such property; and

	•	rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the royalty interests therein.

ECA believes that the burdens and obligations affecting the Underlying Properties and the royalty interests are conventional in the industry for similar properties. ECA also believes that the burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the value of the royalty interest.

ECA believes that its title to the Underlying Properties is, and the trust’s title to the royalty interests will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material as to detract substantially from the use or value of such properties or royalty interests. Consistent with industry practice, ECA has not obtained a preliminary title review of the PUD Wells. Prior to drilling a PUD Well, ECA intends to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examination, certain curative work must be done to correct defects in the marketability of title. ECA does not intend to perform any further title examination prior to the closing of the offering being made hereby. The conveyance related to the PUD Royalty Interest obligates ECA to conduct a more thorough title examination of the drill site tract prior to drilling any of the PUD Wells. ECA will not be relieved of its obligation to drill a well if such title examination prior to drilling reveals a title defect preventing ECA from drilling in such drill site.

It is unclear under Pennsylvania law whether the royalty interests would be treated as real property interests. Nevertheless, ECA intends to record the conveyances of the royalty interests in the real property records of Pennsylvania in accordance with local recording acts. ECA will grant to the trust the Royalty Interest Lien to provide protection to the trust, in the event of a

bankruptcy of ECA, against the risk that the royalty interests were not considered real property interests.

COMPETITION AND MARKETS

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 of their need to sell natural gas at any price to attempt to maintain cash flow. The trust will be 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 impact 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 and demand, future gas prices or the effect of future gas prices on the trust.

REGULATION

Natural gas regulation. The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. Neither ECA nor the trust can predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the Underlying Properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Environmental regulation. The exploration, development and production operations of ECA are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct drilling, water withdrawal and waste disposal operations; govern the amounts and types of substances that may be disposed or released into the environment; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from ECA’s operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties,

the imposition of remedial obligations and the issuance of orders enjoining some or all of ECA’s operations in affected areas.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on ECA’s operations and financial position. ECA may be unable to pass on such increased compliance costs to its customers. Moreover, accidental releases or spills may occur in the course of ECA’s operations, and there can be no assurance that ECA will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property and natural resources or personal injury. While ECA believes that it is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on it, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which ECA’s business operations are subject and for which compliance may have a material adverse impact on ECA’s capital expenditures, results of operations or financial position.

Hazardous Substances and Wastes. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, (“CERCLA”), also known as the Superfund law and comparable state laws impose liability without regard to 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 current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. ECA generates materials in the course of ECA’s operations that may be regulated as hazardous substances.

ECA also generates solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of its operations, ECA generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.

ECA currently owns or leases, and in the past may have owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although ECA may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by ECA or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under ECA’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, ECA could be required to remove or

remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations to prevent future contamination.

Air Emissions. The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require ECA to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of natural gas projects. While ECA may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, ECA does not believe that such requirements will have a material adverse effect on its operations.

Climate Change. In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” (“ACESA”) on June 26, 2009, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs that may contribute to warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17 percent reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to major sources of GHG emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and President Obama has indicated his support of legislation to reduce GHG emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address GHG emissions could require ECA to incur increased operating costs and could adversely affect demand for the natural gas that it produces.

In addition, on December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other 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. 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 proposed regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including sources emitting more than 25,000 tons of GHGs on an annual basis, beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced a proposed rulemaking that would expand its final rule on reporting of GHG emissions to include owners and operators of onshore oil and natural gas production. If the proposed rule is finalized in its current form, reporting of GHG emissions from such onshore production would be required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, ECA’s equipment and operations 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. Finally, it should be

noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on ECA’s assets and operations.

Even if such legislation is not adopted at the national level, more than one-third of the 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. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on ECA’s business, financial condition and results of operations.

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 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. 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 Pennsylvania, require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

It is customary to recover natural gas from deep shale formations, including the Marcellus Shale formation, through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. In particular, two companion bills have been introduced in the U.S. Congress entitled the “Fracturing Responsibility and Awareness of Chemicals Act” to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Sponsors of these bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers. These bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for ECA to perform hydraulic fracturing. Any increased federal, state or local regulation could reduce the volumes of natural gas that ECA produces, which would materially adversely affect its revenues and results of operations. Moreover, in March 2010, the EPA announced that it has allocated $1.9 million in 2010 and has requested funding in fiscal year 2011 for conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing activities.

Endangered Species Act. The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. While some of ECA’s facilities or leased acreage may be located in areas that are designated as habitat for endangered or threatened species, ECA believes that it is in substantial compliance with the ESA. However, 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.

Employee Health and Safety. The operations of ECA are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in ECA’s operations and that this information be provided to employees, state and local government authorities and citizens. ECA believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

State regulation. Pennsylvania regulates 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. Realized prices are not currently subject to state regulation or subject to other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from ECA’s wells and to limit the number of wells or locations ECA can drill.

DESCRIPTION OF THE ROYALTY INTERESTS

The royalty interests will be conveyed to the trust by ECA by means of conveyance instruments that will be recorded in the appropriate real property records in Greene County, Pennsylvania where the gas properties to which the Underlying Properties relate are located. The PDP Royalty Interest will burden the existing working interests owned by ECA in the Producing Wells. ECA has an average working interest of approximately 93% in these wells.

The PUD Royalty Interest will initially burden 50% of all of the interests of ECA in the Marcellus Shale formation in the AMI. ECA’s interests in the gas properties to which the PUD Wells relate consist of an average working interest of 100%. The conveyance related to the PUD Royalty Interest, however, provides that the proceeds from the PUD Wells will be calculated on the basis that the PUD Wells are only burdened by interests that in total would not exceed 12.5%. In the event that ECA’s interest in any of the wells subject to the PUD Royalty Interest that are drilled is subject to burdens in excess of a 12.5%, such burdens will be fully allocated against ECA’s retained interest in such well, the net effect of which is that the trust will receive payments with respect to the PUD Royalty Interest as if the burdens effecting the PUD Wells were in total 12.5% (proportionately reduced). Please see “The Trust — Administrative and Drilling Services Agreement” for a description of the drilling obligations of ECA to the trust.

Generally, the percentage of production proceeds to be received by the trust with respect to a well will equal the product of (i) the percentage of proceeds to which the trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECA’s net revenue interest in the well. ECA on average owns an 81.78% net revenue interest in the Producing Wells. Therefore, the trust will be entitled to receive on average 73.60% of the proceeds of production from the Producing Wells. With respect to a PUD Well, the conveyance related to the PUD Royalty Interest provides that the proceeds from the PUD Wells will be calculated on the basis that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the revenues from such properties, regardless of whether the royalty interest owners are actually entitled to a greater percentage of revenues from such properties. As the applicable net revenue interest of a well is calculated by multiplying ECA’s percentage working interest in such well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the trust would be entitled to 43.75% of the production proceeds from such well. To the extent ECA’s working interest in a PUD Well is less than 100%, the trust’s share of proceeds would be proportionately reduced. Pursuant to the Administrative and Drilling Services Agreement, however, ECA will only satisfy its drilling obligation when it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the requirement to drill additional wells.

PDP Royalty Interest. The conveyances creating the PDP Royalty Interest entitle the trust to receive an amount of cash for each calendar quarter equal to 90% of the proceeds (after deducting post–production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the Producing Wells regardless of whether such amounts have actually been received by ECA from the purchases of the natural gas produced. Proceeds from the sale of natural gas production attributable to the Producing Wells in any calendar quarter means:


	•	amount calculated based on estimated production volumes attributable to the Producing Wells;

in each case, after deducting the trust’s proportionate share of:


	•	any taxes levied on the severance or production of the natural gas produced from the Producing Wells and any property taxes attributable to the natural gas production attributable to the Producing Wells; and

	•	post-production costs, which will generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Service Fee to the extent it is necessary to recover certain capital expenditures in ECA’s Greene County Gathering System. Additionally, the trust will be charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.

Proceeds payable to the trust from the sale of natural gas production attributable to the Producing Wells in any calendar quarter will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas production attributable to the Producing Wells, including any costs to plug and abandon a Producing Well.

PUD Royalty Interest. The conveyances creating the PUD Royalty Interest entitles the trust to receive an amount of cash for each calendar quarter equal to 50% of the proceeds (after deducting post–production costs and any applicable taxes) from the sale of estimated natural gas production attributable to the PUD Wells regardless of whether such amounts have actually been received by ECA from the purchase of the natural gas produced. Proceeds from the sale of natural gas production, if any, attributable to the PUD Wells in any calendar quarter means:


	•	for any calendar quarter commencing on or after April 1, 2010, the amount calculated based on estimated production volumes attributable to the PUD Wells:

in each case after deducting the trust’s proportionate share of:


	•	any taxes levied on the severance or production of the natural gas produced from the PUD Wells and any property taxes attributable to the gas produced from the PUD Wells; and

	•	post-production costs will generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production charges on its with ECA’s Greene County Gathering System will be limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Services Fee to the extent is necessary to recover certain capital expenditures in ECA’s Greene County Gathering System. Additionally, the trust will be charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used.

Proceeds, if any, payable to the trust from the sale of natural gas production attributable to the PUD Wells in any calendar quarter:


	•	will be determined on the basis that ECA’s working interest with respect to the PUD Wells is not subject to burdens (landowner’s royalties and other similar interests) in excess of 12.5% of the proceeds from gas production attributable to ECA’s interest; and


	•	will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas production attributable to the underlying PUD properties, including any costs to plug and abandon a well included in the underlying PUD properties.

Royalty Interest Lien

Under the laws of Pennsylvania, it is not clear that the royalty interests conveyed by ECA to the trust would be treated as real property interests. Therefore, ECA will grant to the trust the Royalty Interest Lien to provide protection to the trust, exercisable in the event of a bankruptcy of ECA, against the risk that the royalty interests were not considered real property interests. More specifically, the Royalty Interest Lien will be a lien in the Subject Interest and the Subject Gas, to the extent and only to the extent that such Subject Interest and Subject Gas pertains to Gas in, under and that may be produced, saved or sold from the Marcellus Shale formation from the wellbore of the Producing Wells and the PUD Wells, sufficient to cause the trust to receive a volume of Trust Gas calculated in accordance with the provisions of the conveyances of the royalty interests. Capitalized terms used in the preceding sentence and not otherwise defined in this prospectus shall have the following meanings:

“Gas” means natural gas and all other gaseous hydrocarbons, excluding condensate, butane, and other liquid and liquefiable components that are actually removed from the Gas stream by separation, processing, or other means.

“Subject Gas” means Gas from the Marcellus Shale formation from any Producing Well or PUD Well.

“Subject Interest” means ECA’s undivided interests in the AMI, as lessee under Gas leases, as an owner of the Subject Gas (or the right to extract such Gas), or otherwise, by virtue of which undivided interests ECA has the right to conduct exploration and Gas production operations on the AMI.

“Trust Gas” means that percentage of Gas to which the Trust is entitled, calculated in accordance with the provisions of the conveyances of the royalty interests.

It is expressly understood and agreed that the Royalty Interest Lien shall not include ECA’s retained interest in the PUD and Producing Wells and the AMI or other interest of ECA in the AMI, and ECA shall have the right to lien, mortgage, sell or otherwise encumber the ECA retained interest subject to the Royalty Interest Lien.

ECA will record the conveyances of the royalty interests and a Mortgage/Fixture Filing in the real estate records of Greene County, Pennsylvania and will file a corresponding UCC-1 Financing Statement in the Office of the Secretary of State of West Virginia and the Commonwealth of Pennsylvania.

Hedging Contracts Transferred to the Trust

At the closing of this offering, ECA will also transfer to the trust natural gas derivative floor price contracts and enter into back-to-back swap agreements with the trust to provide the trust with the benefit of certain contracts entered into between ECA and third parties that equate to approximately 50% of the estimated natural gas to be produced by the trust properties from April 1, 2010 through March 31, 2014. The swap contracts will relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period

commencing as of April 1, 2010 through June 30, 2012. The price of any floor price hedging contract is $5.00 per MMBtu.

The following table sets forth the volumes of natural gas covered by the natural gas hedging contracts and the floor price for each quarter during the term of the contracts.


	Swap Volume		Swap Price		Floor Volume		Floor Price
	(MMBtu)		(MMBtu)		(MMBtu)		(MMBtu)

Second Quarter 2010		682,500	$	6.75		—		—
Third Quarter 2010		690,000	$	6.75		—		—
Fourth Quarter 2010		690,000	$	6.75		225,000	$	5.00
First Quarter 2011		675,000	$	6.75		159,000	$	5.00
Second Quarter 2011		682,500	$	6.75		210,000	$	5.00
Third Quarter 2011		690,000	$	6.82		405,000	$	5.00
Fourth Quarter 2011		690,000	$	6.82		384,000	$	5.00
First Quarter 2012		682,500	$	6.82		369,000	$	5.00
Second Quarter 2012		682,500	$	6.82		516,000	$	5.00
Third Quarter 2012						1,305,000	$	5.00
Fourth Quarter 2012						1,362,000	$	5.00
First Quarter 2013						1,395,000	$	5.00
Second Quarter 2013						1,380,000	$	5.00
Third Quarter 2013						1,278,000	$	5.00
Fourth Quarter 2013						1,188,000	$	5.00
First Quarter 2014						1,092,000	$	5.00

The conveyances also provide that if ECA’s interest with respect to the PDP properties is greater than what was warranted to the trust in the conveyances, ECA will have the right to offset against amounts owed to the trust, the difference between what the trust actually receives from PDP Royalty Interest and what the trust should have received from the PDP Royalty Interest had ECA’s interest been the amount warranted.

The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. The Term Royalties will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds thereof will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the Perpetual Royalties at the Termination Date.

ADDITIONAL PROVISIONS

If a controversy arises as to the sales price of any production, then for purposes of determining gross proceeds:


	•	amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected;

	•	amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and


	•	amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received.

The trustee is not obligated to return any cash received from the royalty interests. Any overpayments made to the trust by ECA due to adjustments to prior calculations of proceeds or otherwise will reduce future amounts payable to the trust until ECA recovers the overpayments.

The conveyances generally permit ECA to transfer without the consent or approval of the trust unitholders all or any part of its interest in the Underlying Properties, subject to the royalty interests. Notwithstanding the foregoing, the Administrative and Drilling Services Agreement provides that ECA may not sell any of the Underlying Properties subject to the PUD Royalty Interest until it has satisfied its obligation to drill PUD Wells pursuant to the terms of the Administrative and Drilling Services Agreement. The trust unitholders are not entitled to any proceeds of any sale or transfer of ECA’s interest in the Underlying Properties. Following a sale or transfer, the Underlying Properties will continue to be subject to the royalty interests, and the proceeds attributable to the transferred property will be calculated as described in this prospectus, and paid by the purchaser or transferee to the trust. As a result, any additional costs resulting from the transferred property will not reduce the proceeds paid to the trust from the Underlying Properties retained by ECA.

ECA or any transferee of an Underlying Property will have the right to abandon any well or property if it reasonably believes the well or property ceases to produce or is not capable of producing in commercially paying quantities. In making such decisions, ECA or any transferee of an Underlying Property is required under the applicable conveyance to act as a reasonably prudent operator in the AMI under the same or similar circumstances would act if it were acting with respect to its own properties, disregarding the existence of the royalty interests as burdens affecting such property. Upon termination of the lease, that portion of the royalty interests relating to the abandoned property will be extinguished.

ECA may, without the consent of the trust unitholders, require the trust to release royalty interests with an aggregate value to the trust up to $5.0 million during any 12-month period. These releases will be made only in connection with a sale by ECA of the Underlying Properties and are conditioned upon the trust receiving an amount equal to the fair value to the trust of such royalty interests.

ECA must maintain books and records sufficient to determine the amounts payable for the royalty interests to the trust. Quarterly and annually, ECA must deliver to the trustee a statement of the computation of the proceeds for each computation period as well as quarterly drilling and production results. Following the completion of this offering, ECA will not be obligated to publicly file any reports with the SEC.

DESCRIPTION OF THE TRUST AGREEMENT

CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS

In connection with the formation of the trust, ECA will convey to a wholly owned subsidiary a term royalty interest entitling the holder of the interest to receive 45% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 the Term PDP Royalty and a term royalty interest entitling such holder of the interest to receive 25% of the proceeds from the sale of the production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years commencing on April 1, 2010 (the “Term PUD Royalty”) in exchange for a demand note in the principal amount of $ million. The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the “Term Royalties.”

Prior to the closing of this offering, ECA and the Private Investors will convey to the trust perpetual royalty interests entitling the trust to receive, in the aggregate, an additional 45% of the proceeds from the sale of production of natural gas attributable to the interests of ECA in the Producing Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PDP Royalty”) and ECA will convey to the trust a perpetual royalty interest entitling the trust to receive an additional 25% of the proceeds from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells (after deducting post-production costs and any applicable taxes) (the “Perpetual PUD Royalty”) in exchange for an aggregate 4,500,000 common units constituting 25% of the trust units outstanding and 4,500,000 subordinated units constituting 25% of the trust units outstanding. The Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the “Perpetual Royalties.”

In connection with the completion of this offering, ECA’s subsidiary will convey the Term Royalties to the trust in exchange for the proceeds of this offering, after deducting underwriting commissions and discounts and expenses, and will use such proceeds to repay the demand note to ECA.

The trust was created under Delaware law to acquire and hold the royalty interests for the benefit of the trust unitholders pursuant to an agreement between ECA, the trustee and the Delaware trustee. The royalty interests are passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the Underlying Properties. Neither ECA nor other operators of the Underlying Properties have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of these properties other than the obligations of ECA to designate and drill PUD Wells. After the conveyance of the royalty interests, however, ECA will retain an interest in each of the Underlying Properties. For a description of the Underlying Properties and other information relating to them, see “The Underlying Properties.”

The trust agreement will provide that the trust’s business activities will be limited to owning the royalty interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the royalty interests and the natural gas hedging contracts relating to an estimated 50% of the trust’s royalty production for a term ending March 31, 2014. As a result, the trust will not be permitted to acquire other oil and gas properties or royalty interests.

The beneficial interest in the trust is divided into 18,000,000 trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. Please read “Description of the trust units” for additional information concerning the Trust Units.

Amendment of the trust agreement requires a vote of holders of a majority of the outstanding trust units. However, no amendment may:


	•	increase the power of the trustee to engage in business or investment activities;

	•	alter the rights of the trust unitholders as among themselves; or

	•	permit the trustee to distribute the royalty interests in kind.

Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity or to correct or supplement any defective or inconsistent provisions provided such supplement or amendment is not adverse to the interest of the trust unitholders. The business and affairs of the trust will be managed by the trustee. Although ECA will operate all of the Producing Wells and substantially all of the PUD Wells during the subordination period, ECA has no ability to manage or influence the management of the trust.

ASSETS OF THE TRUST

Upon completion of this offering, the assets of the trust will consist of royalty interests, natural gas hedging contracts, the Administrative and Drilling Services Agreement that obligates ECA to drill the PUD Wells and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.

DUTIES AND POWERS OF THE TRUSTEE

The duties of the trustee are specified in the trust agreement and by the laws of the State of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:


	•	collecting cash attributable to the royalty interests;

	•	paying expenses, charges and obligations of the trust from the trust’s assets;

	•	determining whether cash distributions exceed subordination or incentive thresholds, and making such cash distributions to the common and subordinated unitholders accordingly;

	•	causing to be prepared and distributed a Schedule K-1 for each trust unitholder and to prepare and file tax returns on behalf of the trust;

	•	causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading; and

	•	taking any action it deems necessary and advisable to best achieve the purposes of the trust.

If a trust liability is contingent or uncertain in amount or not yet currently due and payable, the trustee may create a cash reserve to pay for the liability. If the trustee determines that the cash on hand and the cash to be received are insufficient to cover the trust’s liability, the trustee may borrow funds required to pay the liabilities. The trustee may borrow the funds from any person, including itself or its affiliates. The trustee may also mortgage the assets of the trust to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were

loaned by the entity serving as trustee or Delaware trustee, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee borrows funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

Each quarter, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the royalty interests. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:


	•	interest bearing obligations of the United States government;

	•	money market funds that invest only in United States government securities;

	•	repurchase agreements secured by interest-bearing obligations of the United States government; or

	•	bank certificates of deposit.

The trust may not acquire any asset except the royalty interests, the natural gas hedging contracts, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the outstanding trust units and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.

The trustee may sell the royalty interests under any of the following circumstances:


	•	the sale does not involve a material part of the trust’s assets and is in the best interests of the trust unitholders; or

	•	the sale constitutes a material part of the trust’s assets and is in the best interests of the trust unitholders, subject to the holders representing a majority of the outstanding trust units approving the sale.

Upon dissolution of the trust the trustee must sell the royalty interests. No trust unitholder approval is required in this event.

The trustee will distribute the net proceeds from any sale of the royalty interests and other assets to the trust unitholders.

The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them and to borrow funds to make that purchase.

The trustee may agree to modifications of the terms of the conveyances or to settle disputes involving the conveyances. The trustee may not agree to modifications or settle disputes involving the royalty part of the conveyances if these actions would change the character of the royalty interests in such a way that the royalty interests become net revenue interests or that the trust becomes an operating business.

LIABILITIES OF THE TRUST

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees and accounting, engineering, legal, tax advisory and other professional fees.

FEES AND EXPENSES

Ongoing administrative expenses. The trust will be responsible for paying all legal, accounting, tax advisory, engineering, printing and other administrative and out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. The trust will also be responsible for paying other expenses incurred as a result of its being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees. These trust administrative expenses as well as the costs associated with being a publicly traded entity are initially anticipated to aggregate approximately $800,000 per year, although such costs could be greater or less depending on future events that cannot be predicted. Included in the $800,000 annual estimate is an annual administrative fee of $ for the trustee and an annual administrative fee of $ for the Delaware trustee. These costs as well as those to be paid to ECA pursuant to the Administrative and Drilling Services Agreement outlined under “The Trust — Administrative and Drilling Services Agreement,” will be deducted by the trust before distributions are made to trust unitholders.

Fees to ECA. The Administrative and Drilling Services Agreement provides that the trust is obligated, throughout the term of the trust, to pay to ECA each quarter an administrative services fee for accounting, bookkeeping and informational services relating to the royalty interests. The annual fee, payable in equal quarterly installments, will total $60,000 per year.

FIDUCIARY RESPONSIBILITY AND LIABILITY OF THE TRUSTEE

Under the trust agreement, the trustee is required to act in the best interests of the trust unitholders at all times. The trustee must exercise the same judgment and care in supervising and managing the trust’s assets as persons of ordinary prudence, discretion and intelligence would exercise.

The trustee will not make business decisions affecting the assets of the trust. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. See “— Duties and Powers of the Trustee,” above. The trust agreement, however, provides that the trustee may:


	•	charge for its services as trustee;

	•	retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);


	•	lend funds at commercial rates to the trust to pay the trust’s expenses; and

	•	seek reimbursement from the trust for its out-of-pocket expenses.

In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for fraud, gross negligence or acts or omissions constituting bad faith. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted in bad faith or with gross negligence in their selection and retention. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or bad faith. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. See “Description of the Trust Units — Liability of trust unitholders.” The trustee must ensure that all contractual liabilities of the trust are limited to the assets of the trust and the trustee will be liable for its failure to do so.

DURATION OF THE TRUST; SALE OF ROYALTY INTERESTS

The trust will remain in existence until the Termination Date, which is March 31, 2030. The trust will dissolve prior to the Termination Date if:


	•	the trust sells all of the royalty interests;

	•	gross proceeds attributable to the royalty interests are less than $1.5 million for any four consecutive quarters;

	•	the holders of a majority of the outstanding trust units vote in favor of dissolution; or

	•	judicial dissolution of the trust.

The trustee would then sell all of the trust’s assets, either by private sale or public auction, and distribute the net proceeds of the sale to the trust unitholders.

DISPUTE RESOLUTION

Any dispute, controversy or claim that may arise between ECA and the trustee relating to the trust will be submitted to binding arbitration before a panel of three arbitrators.

COMPENSATION OF THE TRUSTEE AND THE DELAWARE TRUSTEE

The trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s assets. See “— Fees and Expenses.”

TAX MATTERS

Trust unitholders will be treated as partners of the trust for federal income tax purposes. The trust agreement contains tax provisions that generally allocate the trust’s income, gain, loss, deduction and credit among the trust unitholders in accordance with their percentage interests in the trust. The trust agreement also sets forth the tax accounting principles to be applied by the trust.

MISCELLANEOUS

The trustee may consult with counsel, accountants, tax advisors, geologists and engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected for any action it takes in good faith reliance upon the opinion of the expert.

The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, TX 78701, and its telephone number is 512-236-6599.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by a vote of not less than a majority of the outstanding trust units. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20 million, in the case of the Delaware trustee, and $100 million, in the case of the trustee.

DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of the beneficial interest in the trust and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust will have 18,000,000 trust units outstanding upon completion of the offering, consisting of 13,500,000 common units and 4,500,000 subordinated units.

DISTRIBUTIONS AND INCOME COMPUTATIONS

Cash distributions to trust unitholders will be made from available funds at the trust for each calendar quarter. Production payments due to the trust with respect to any calendar quarter will be accrued based on estimated production volumes attributable to the trust properties during such quarter (as measured at ECA metering systems) and market prices for such volumes. ECA will make a payment to the trust equal to such accrued amounts within 30 days of the end of such calendar quarter. After receipt of such payment, the trustee will determine for such calendar quarter the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust over the trust’s expenses for that quarter. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. Any difference between the payment made by ECA to the trust with respect to a calendar quarter and the actual cash production payments relative to the trust properties received by ECA will be netted against future payments by ECA to the trust. As a result, during the subordination period, the netting of such difference could result in (i) an inability by the trust to make cash distributions in excess of applicable subordination thresholds with respect to a subsequent calendar quarter or (ii) distributions in excess of the incentive thresholds for a prior calendar quarter notwithstanding the fact that such shortfall or excess, respectively, would not have existed had production payments owed to the trust been calculated on an actual cash basis.

The amount of available funds for distribution each quarter will be payable to the trust unitholders of record on or about the 45th day 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. It is expected that the trustee will be able to distribute cash on or about the 60th day (or the next succeeding business day following such day if such day is not a business day) following such calendar quarter to each person who was a trust unitholder of record on the quarterly record date, together with interest expected to be earned on the amount of such quarterly distribution from the date of receipt thereof by the trustee to the payment date.

Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the first business day of the month. Trust unitholders will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes them. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. The trustee could also make a payment in one month that would be amortized for tax purposes over several months. See “Federal income tax considerations.”

TRANSFER OF TRUST UNITS

Trust unitholders may transfer their trust units by sending their trust unit certificate to the trustee along with a transfer form that is properly completed. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The

trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any quarterly record date will not be entitled to the distribution relating to that quarterly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.

PERIODIC REPORTS

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders a Schedule K-1 that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours the records of the trust and the trustee.

LIABILITY OF TRUST UNITHOLDERS

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

VOTING RIGHTS OF TRUST UNITHOLDERS

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send written notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned.

Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the vote of a majority of the trust units held by the trust unitholders at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of a majority of the outstanding trust units is required to:


	•	dissolve the trust;

	•	remove the trustee or the Delaware trustee;

	•	amend the trust agreement (except with respect to certain matters that do not adversely affect the right of trust unitholders in any material respect);

	•	merge or consolidate the trust with or into another entity; or

	•	approve the sale of all or any material part of the assets of the trust.

In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. The trustee must consent before all or any part of the trust assets can be sold except in connection with the dissolution of the trust or limited sales directed by ECA in conjunction with its sale of Underlying Properties.

COMPARISON OF TRUST UNITS AND COMMON STOCK

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

Unitholders should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.


	Trust units	Common stock

Voting	Trust agreement provides voting rights to trust unitholders to remove and replace trustee (but not elect) and to approve or disapprove major trust transactions.	Corporate statutes provide voting rights to stockholders of the corporation to elect directors and to approve or disapprove major corporate transactions.
Income Tax	The trust is not subject to federal income tax; trust unitholders are subject to income tax on their allocable share of trust income, gain, loss and deduction.	Corporations are taxed on their income, and their stockholders are taxed on dividends.
Distributions	Substantially all trust revenue is distributed to trust unitholders.	Stockholders receive dividends at the discretion of the board of directors.
Business and Assets	The business of the trust is limited to specific assets with a finite economic life.	A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.
Fiduciary Duties	To the extent provided in the trust agreement, the trustee has a fiduciary duty to the trust unitholders.	Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation.

TRUST UNITS ELIGIBLE FOR FUTURE SALE

General

Prior to this offering, there has been no public market for the common units. Sales of substantial amounts of the common units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be 18,000,000 trust units outstanding. All of the 9,000,000 common units sold in this offering, or the 10,350,000 common units if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act. The 1,104,567 common units to be held by the Private Investors and the 7,895,433 trust units to be held by ECA (6,545,433 trust units if the underwriters exercise their over-allotment in full) following completion of the offering will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting.”

Lock-up Agreements

In connection with this offering, ECA and the Private Investors have agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units, other than the sale of 209,316 common units to ECA by the Private Investors, without the prior written consent of Raymond James & Associates, Inc. and Citigroup Global Markets Inc., subject to specified exceptions. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements, all of the common units held by ECA and the Private Investors will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

Rule 144

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ECA or the trust may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1.0% of the total number of the securities outstanding, or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of ECA or the trust at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s

public information requirements, volume limitations, manner of sale provisions and notice requirements.

Registration Rights

The trust intends to enter into a registration rights agreement with ECA and the Private Investors in connection with ECA’s conveyance to the trust of the PDP Royalty Interest and the PUD Royalty Interest. In the registration rights agreement, the trust will agree, for the benefit of ECA, the Private Investors and any of their transferees (each, a “holder”), to register the trust units it holds. Specifically, the trust will agree:


	•	subject to the restrictions described above under “— Lock-up Agreements” and under “Underwriting — Lock-up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;

	•	to use its reasonable best efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

	•	to continuously maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement or until all registrable trust units:


	•	have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities;”

	•	have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units; or

	•	become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).

ECA and the Private Investors will have the right to require the trust to file no more than three registration statements in aggregate.

In connection with the preparation and filing of any registration statement, ECA will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trustee, and any underwriting discounts and commissions, which will be borne by the seller of the trust units.

FEDERAL INCOME TAX CONSIDERATIONS

This section is a discussion of the material tax considerations that may be relevant to prospective trust unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to ECA and the trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Future changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

The following discussion does not address all federal income tax matters affecting the trust or the trust unitholders. Moreover, the discussion focuses on trust unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, taxpayers subject to the alternative minimum tax, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, the trust encourages each prospective trust unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of trust units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting the trust or prospective trust unitholders. Instead, the trust will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the trust units and the prices at which trust units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to the trust unitholders, and thus will be borne indirectly by the trust unitholders. Furthermore, the tax treatment of the trust, or of an investment in the trust, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by ECA and the trust.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units (please read “— Tax Consequences of Trust Unit Ownership — Treatment of Short Sales”); (2) whether the trust’s monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Trust Units — Allocations Between Transferors and Transferees”); and (3) whether percentage depletion will be available to a trust unitholder or the extent of the percentage depletion deduction available to any trust unitholder (please read “— Tax Consequences of Trust Unit Ownership — Tax Treatment of the Perpetual Royalties”.

As used herein, the term “trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:


	•	an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes,

	•	a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,

	•	an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

	•	a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person.

The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit (other than an entity that is classified for U.S. federal income tax purposes as a partnership or as a “disregarded entity”) that is not a trust unitholder.

If an entity that is classified for U.S. federal income tax purposes as a partnership is a beneficial owner of trust units, the tax treatment of a member of the entity will depend upon the status of the member and the activities of the entity. The trust encourages any entity that is classified for U.S. federal income tax purposes as a partnership and that is a beneficial owner of trust units, and the members of such an entity, to consult their own tax advisors about the U.S. federal income tax considerations of purchasing, owning, and disposing of trust units.

CLASSIFICATION OF THE TRUST AS A PARTNERSHIP

Although the trust is formed as a statutory trust under Delaware law, the trust’s classification for federal income tax purposes is based on its characteristics rather than its form. Based on such characteristics, it is expected that, as described below, the trust will be treated for federal and applicable state income tax purposes as a partnership and trust unitholders will be treated as partners in that partnership.

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss, deduction and credit of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest as of the end of the taxable year in which the distribution is made.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, production and marketing of crude oil and natural gas and interest income (other than from a financial business). Other types of qualifying income include gains from the sale of real property and income from certain hedging transactions. The trust anticipates that substantially all of its

gross income will be qualifying income. Based upon the factual representations made by the trust and ECA and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of the trust’s gross income will constitute qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to the trust’s status for federal income tax purposes or whether the trust’s operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, the trust will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below, the trust will be classified as a partnership for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by the trust and ECA. The representations made by the trust and ECA upon which Vinson & Elkins L.L.P. has relied are:

(a) The trust has not, and will not, elect to be treated as a corporation;

(b) The trust is, and will be organized and operated in accordance with (i) all applicable trust statutes, including the Delaware Statutory Trust Act, (ii) the trust agreement, and (iii) the description thereof in this prospectus;

(c) For each taxable year, more than 90% of the trust’s gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is qualifying income within the meaning of Section 7704(d) of the Internal Revenue Code; and

(d) Each hedging transaction that the trust treats as resulting in qualifying income will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and will be associated with oil, gas or products thereof that are held or will be held by the trust in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

The trust believes that these representations are true and expects that these representations will continue to be true in the future.

If the trust fails to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require the trust to make adjustments with respect to the trust’s unitholders allocable share of trust income, gain, loss or deduction or pay other amounts), the trust will be treated as if it had transferred all of its assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which the trust fails to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in the trust. This deemed contribution and liquidation should be tax-free to the trust unitholders and the trust. Thereafter, the trust would be treated as an association taxable as a corporation for federal income tax purposes.

If the trust were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, the trust’s items of income, gain, loss and deduction would be reflected only on the trust’s tax return rather than being passed through to the trust unitholders, and the trust’s net income would be taxed to the trust at corporate rates. In addition, any distribution made to a trust unitholder would be treated as either taxable dividend income, to the extent of the trust’s current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent

of the trust unitholder’s tax basis in his trust units, or taxable capital gain, after the trust unitholder’s tax basis in his trust units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a trust unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the trust units.

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that the trust will be classified as a partnership for federal income tax purposes.

PARTNER STATUS

Trust unitholders will be treated as partners of ECA Marcellus Trust I for federal income tax purposes. Also, trust unitholders whose trust units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their trust units will be treated as partners of ECA Marcellus Trust I for federal income tax purposes.

A beneficial owner of trust units whose trust units have been transferred to a short seller to complete a short sale would appear, as a result, to lose his status as a partner with respect to those trust units for federal income tax purposes. Please read “— Tax Consequences of Trust Unit Ownership — Treatment of Short Sales.” Income, gain, deductions or losses would not appear to be reportable by a trust unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a trust unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to their tax considerations related to holding trust units. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in ECA Marcellus Trust I for federal income tax purposes.

TAX CLASSIFICATION OF THE PDP ROYALTY INTEREST AND THE PUD ROYALTY INTEREST

For federal income tax purposes, the PDP Royalty Interest and the PUD Royalty Interest will have the tax characteristics of mineral royalty interests to the extent they are, at the time of their creation, reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.

In contrast, the PDP Royalty Interest and the PUD Royalty Interest will have the tax characteristics of production payments governed by Section 636 of the Internal Revenue Code to the extent they may not, at the time of their creation, be reasonably expected to extend in substantial amounts over the entire productive lives of the mineral property or properties they burden. Payments out of production that are received in respect of a mineral interest that constitutes a production payment for federal income tax purposes are treated under current law as consisting of a receipt of principal and interest on a nonrecourse debt obligation, with the interest component being taxable as ordinary income.

In the event that a portion of a single royalty interest terminates by its terms prior to the point in time that the economically productive life of the burdened mineral property is substantially exhausted and the remaining portion continues to burden the property until its economically productive life is substantially exhausted, the federal income tax characteristics of the royalty interest are determined as if it comprised two separate interests, with the terminating

portion being treated as a production payment and the continuing portion being treated as a royalty interest.

Based on the reserve report and representations made by ECA regarding the expected economic life of the Underlying Properties and the expected duration of the Term Royalties and the Perpetual Royalties, the Term PDP Royalty will and the Term PUD Royalty should be treated as “production payments” under Section 636 of the Internal Revenue Code, and thus as nonrecourse debt instruments of ECA for U.S. federal income tax purposes. The Perpetual PDP Royalty will and the Perpetual PUD Royalty should be treated as continuing, nonoperating economic interest in the nature of royalties payable out of production from the mineral interests they burden.

Consistent with this characterization, ECA and the trust intend to treat the Perpetual Royalties as mineral royalty interests for federal income tax purposes. In addition, ECA and the trust intend to treat the Term Royalties as debt instruments for U.S. federal income tax purposes subject to the Treasury Regulations applicable to contingent payment debt instruments (the “CPDI regulations”), and the trust will agree to be bound by ECA’s application of the CPDI regulations, including ECA’s determination of the rate at which interest will be deemed to accrue on the such interests. The remainder of this discussion assumes that the Term Royalties will be treated in accordance with that agreement and ECA’s determinations and that the Perpetual Royalties will be treated as mineral royalty interests. No assurance can be given that the IRS will not assert that such interests should be treated differently. Such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units and could require a trust unitholder to accrue interest income at a rate different than the “comparable yield” described below. Please read “— Tax Consequences of Trust Unit Ownership — Tax Treatment of the Term Royalties,” and “— Tax Consequences of Trust Unit Ownership — Tax Treatment of the Perpetual Royalties.”

TAX CONSEQUENCES OF TRUST UNIT OWNERSHIP

Flow-Through of Taxable Income

As a partnership for federal income tax purposes, the trust will not be a taxable entity required to pay any federal income tax. Instead, each trust unitholder will be required to report on his income tax return his allocable share of the trust’s income, gains, losses, deductions and credits without regard to whether the trust makes cash distributions to him. Consequently, the trust may allocate taxable income to a trust unitholder even if he has not received a cash distribution.

Accounting Method and Taxable Year

The trust will use the year ending December 31 as its taxable year and the accrual method of accounting for federal income tax purposes. Each trust unitholder will be required to include in income his share of the trust’s income, gain, loss, deduction and credit for the trust’s taxable year ending within or with his taxable year. In addition, a trust unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his trust units following the close of the trust’s taxable year but before the close of his taxable year must include his share of the trust’s income, gain, loss, deduction and credit in his taxable income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of the trust’s income, gain, loss, deduction and credit. Please read “— Disposition of Trust Units — Allocations Between Transferors and Transferees.”

Basis of Trust Units

A trust unitholder’s initial tax basis for his trust units will be the amount he paid for the trust units. That basis will be increased by his share of the trust’s income and gain and decreased, but not below zero, by distributions from the trust, by the trust unitholder’s share of the trust’s losses, if any, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate allocated share of the adjusted tax basis of the Perpetual Royalties, and by his share of the trust’s expenditures that are not deductible in computing taxable income and are not required to be capitalized. Please read “— Disposition of Trust Units — Recognition of Gain or Loss.”

Allocation of Income, Gain, Loss, Deduction and Credit

In general, if the trust has a net profit, the trust’s items of income, gain, loss, deduction and credit will be allocated among the trust unitholders in accordance with their percentage interests in the trust. At any time that distributions are made to the common units in excess of distributions to the subordinated trust units, or incentive distributions are made in respect of the subordinated trust units, gross income will be allocated to the recipients to the extent of these distributions. If the trust has a net loss, that loss will be allocated first to the subordinated trust units to the extent of their positive capital accounts and thereafter to the trust unitholders in accordance with their percentage interests in the trust.

Specified items of the trust’s income, gain, loss, deduction and credit will be allocated under Section 704(c) of the Internal Revenue Code to account for any difference between the tax basis and fair market value of any property treated as having been contributed to the trust by ECA or certain of its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” These “Section 704(c) Allocations” are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” The effect of these 704(c) Allocations to a unitholder purchasing trust units from the trust in this offering will be essentially the same as if the tax bases of the trust’s assets were equal to their fair market value at the time of this offering. Finally, although the trust does not expect that its operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of the trust’s income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of the trust’s income, gain, loss, deduction or credit, other than an allocation required by Section 704(c) of the Internal Revenue Code to eliminate the Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss, deduction or credit only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in the trust, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to the trust;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

100

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “Disposition of Trust Units — Allocations Between Transferors and Transferees,” allocations under the trust agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss, deduction or credit.

Treatment of Trust Distributions

Distributions by the trust to a trust unitholder generally will not be taxable to the trust unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his trust units immediately before the distribution. The trust’s cash distributions in excess of a unitholder’s tax basis (if any) generally will be considered to be gain from the sale or exchange of the trust units, taxable in accordance with the rules described under “— Disposition of Trust Units” below.

Ratio of Taxable Income to Distributions

The trust estimates that a purchaser of trust units in this offering who owns those trust units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2012, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.

Tax Treatment of the Term Royalties

Under the CPDI regulations, the trust generally will be required to accrue income on the Term Royalties which are treated as production payments, and therefore as nonrecourse debt obligations of ECA for federal income tax purposes, in the amounts described below.

The CPDI regulations provide that the trust must accrue an amount of ordinary interest income for U.S. federal income tax purposes, for each accrual period prior to and including the maturity date of the debt instrument that equals:


	•	the product of (i) the adjusted issue price (as defined below) of the debt instrument as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period;

	•	divided by the number of days in the accrual period; and

	•	multiplied by the number of days during the accrual period that the trust held the debt instrument.

The “issue price” of the debt instrument represented by each production payment held by the trust is the portion of the first price at which a substantial amount of the trust units is sold to the public, excluding sales to bond houses, brokers or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers, that is allocable to the production payment based on the relative fair market value of the production payment to the other assets of the trust. The “adjusted issue price” of such a debt instrument is its issue price increased by any

101

interest income previously accrued, determined without regard to any adjustments to interest accruals described below, and decreased by the projected amount of any payments scheduled to be made with respect to the debt instrument at an earlier time (without regard to the actual amount paid). The term “comparable yield” means the annual yield ECA would be expected to pay, as of the initial issue date, on a fixed rate debt security with no contingent payments but with terms and conditions otherwise comparable to those of the debt instrument represented by the production payment.

ECA and the trust intend to take the position that the comparable yield for each debt instrument held by the trust is an annual rate of 10%, compounded semi-annually. The CPDI regulations require that ECA provide to the trust, solely for determining the amount of interest accruals for U.S. federal income tax purposes, a schedule of the projected amounts of payments, which are referred to as projected payments, on the Term Royalties treated as debt instruments held by the trust. These payments set forth on the schedule must produce a total return on such debt instruments equal to their comparable yield. Amounts treated as interest under the CPDI regulations are treated as original issue discount for all purposes of the Internal Revenue Code.

As required by the CPDI regulations, for U.S. federal income tax purposes, the trust must use the comparable yield and the schedule of projected payments as described above in determining the trust’s interest accruals, and the adjustments thereto described below, in respect of the debt instruments held by the trust.

ECA’s determinations of the comparable yield and the projected payment schedule are not binding on the IRS and it could challenge such determinations. If it did so, and if any such challenge were successful, then the amount and timing of interest income accruals of the trust would be different from those reported by the trust or included on previously filed tax returns by the trust unitholders.

The comparable yield and the schedule of projected payments are not determined for any purpose other than for the determination for U.S. federal income tax purposes of the trust’s interest accruals and adjustments thereof in respect of the debt instruments held by the trust and do not constitute a projection or representation regarding the actual amounts payable to the trust.

For U.S. federal income tax purposes, the trust is required under the CPDI regulations to use the comparable yield and the projected payment schedule established by ECA in determining interest accruals and adjustments in respect of the production payments, unless the trust timely discloses and justifies the use of a different comparable yield and projected payment schedule to the IRS. Pursuant to the terms of the conveyance, ECA and the trust have agreed (in the absence of an administrative determination or judicial ruling to the contrary) to be bound by ECA’s determination of the comparable yield and projected payment schedule.

If, during any taxable year, the trust receives actual payments with respect to a debt instrument held by the trust that in the aggregate exceed the total amount of projected payments for that taxable year, the trust will incur a “net positive adjustment” under the CPDI regulations equal to the amount of such excess. The trust will treat a “net positive adjustment” as additional interest income for such taxable year.

If the trust receives in a taxable year actual payments with respect to a debt instrument held by the trust that in the aggregate are less than the amount of projected payments for that taxable year, the trust will incur a “net negative adjustment” under the CPDI regulations equal to the amount of such deficit. This adjustment will (a) reduce the trust’s interest income on the debt instrument held by the trust for that taxable year, and (b) to the extent of any excess after the application of (a) give rise to an ordinary loss to the extent of the trust’s interest income on such

102

debt instrument during prior taxable years, reduced to the extent such interest was offset by prior net negative adjustments. Any negative adjustment in excess of the amount described in (a) and (b) will be carried forward, as a negative adjustment to offset future interest income in respect of that debt instrument held by the trust. If either of the Term Royalties is not treated as a production payment (and hence not as a debt instrument) for federal income tax purposes, the trust intends to take the position that its basis in the Term Royalty is recouped in proportion to the production from the Term Royalty.

Neither the trust nor the trust unitholders are entitled to claim depletion deductions with respect to the Term Royalties.

Tax Treatment of the Perpetual Royalties

The payments received by the trust in respect of the Perpetual Royalties treated as mineral royalty interests for federal income tax purposes should be treated as ordinary income. Trust unitholders should be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to such income. Although the Internal Revenue Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interest for depletion and other purposes, the trust intends to furnish each of the trust unitholders with information relating to this computation for federal income tax purposes. Each trust unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the Perpetual Royalties for depletion and other purposes.

Percentage depletion is generally available with respect to trust unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the trust unitholder from the property for each taxable year, computed without the depletion allowance. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

In addition to the limitations on percentage depletion discussed above, on February 1, 2010, the White House released President Obama’s budget proposal for the fiscal year 2011 (the “2011 Budget”). The 2011 Budget proposes to eliminate certain tax preferences applicable to taxpayers

103

engaged in the exploration or production of natural resources effective in 2011. Specifically, the 2011 Budget proposes to repeal the deduction for percentage depletion with respect to oil and natural gas wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when it would become effective.

Trust unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the trust unitholder’s allocated share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the trust unitholder’s share of the total adjusted tax basis in the property.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the trust, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Tax Treatment Upon Sale of the Perpetual Royalties at Termination Date

The sale of the Perpetual Royalties by the trust at or shortly after the Termination Date will generally give rise to long-term capital gain or loss to the trust unitholders for federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Perpetual Royalties. Each trust unitholder will be responsible for calculating his gain or loss based on the difference between his pro-rata share of the amount realized on the sale by the trust and his adjusted basis in the Perpetual Royalties, and if a gain is realized, the portion thereof taxable as ordinary income by reason of depletion deductions previously claimed by such trust unitholder. However, the trust intends to furnish each of the trust unitholders with information relating to this calculation for federal income tax purposes in connection with the final partnership tax return for the trust.

Limitations on Deductibility of Losses

It is not anticipated that the trust will generate losses. Nevertheless, should losses result, trust unitholders must consult their own tax advisors as to the applicability to them of loss limitation rules that could operate to limit the deductibility to a trust unitholder of his share of the trust’s losses such as the basis limitation, the “at risk” rules and the passive loss rules. Special passive loss limitation rules apply with respect to publicly-traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

104


	•	the trust’s interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a trust unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a trust unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest deduction limitation. In addition, the trust unitholder’s share of the trust’s portfolio income will be treated as investment income.

Entity-Level Withholdings

If the trust is required or elects under applicable law to pay any federal, state, local or foreign income tax on behalf of any trust unitholder or any former trust unitholder, the trust is authorized to pay those taxes from its funds. That payment, if made, will be treated as a distribution of cash to the trust unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, the trust is authorized to treat the payment as a distribution to all current trust unitholders. The trust is authorized to amend its trust agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of trust units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the trust agreement is maintained as nearly as is practicable. Payments by the trust as described above could give rise to an overpayment of tax on behalf of an individual trust unitholder in which event the trust unitholder would be required to file a claim in order to obtain a credit or refund.

Treatment of Short Sales

A trust unitholder whose trust units are loaned to a “short seller” to cover a short sale of trust units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those trust units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of the trust’s income, gain, loss, deduction or credit with respect to those trust units would not be reportable by the trust unitholder;

	•	any cash distributions received by the trust unitholder as to those trust units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a trust unitholder whose trust units are loaned to a short seller to cover a short sale of trust units; therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their trust units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of

105

partnership interests. Please also read “— Disposition of Trust Units — Recognition of Gain or Loss.”

Alternative Minimum Tax

Each trust unitholder will be required to take into account his distributive share of any items of the trust’s income, gain, loss, deduction or credit for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective trust unitholders are urged to consult with their tax advisors as to the impact of an investment in trust units on their liability for the alternative minimum tax.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than 12 months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a trust unitholder’s allocable share of the trust’s income and gain realized by a trust unitholder from a sale of trust units. The tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments, and (ii) the amount by which the trust unitholder’s adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly) or $200,000 (if the trust unitholder is not married).

Section 754 Election

The trust will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit the trust to adjust a subsequent trust unit purchaser’s tax basis in the trust’s assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price of trust units acquired from another trust unitholder. The Section 743(b) adjustment belongs to the purchaser and not to other trust unitholders. For purposes of this discussion, a trust unitholder’s inside basis in the trust’s assets will be considered to have two components: (1) his share of tax basis in the trust’s assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of the trust’s assets immediately prior to the transfer. In such a case, as a result of the election, the transferee would have a higher tax basis in his share of the trust’s assets for purposes of calculating, among other items, cost depletion deductions on the Perpetual Royalties, and his share of any gain on a sale of the trust’s assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those trust units’ share of the aggregate tax basis of the trust’s assets immediately prior to the transfer. Thus, the fair market value of the trust units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in the trust if it has a substantial built-in

106

loss immediately after the transfer. Generally a built — in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of the trust’s assets and other matters. For example, the allocation of the Section 743(b) adjustment among the trust’s assets must be made in accordance with the Internal Revenue Code. The trust cannot assure unitholders that the determinations it makes will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in the trust’s opinion, the expense of compliance exceed the benefit of the election, the trust may seek permission from the IRS to revoke its Section 754 election. If permission is granted, a subsequent purchaser of trust units may be allocated more income than he would have been allocated had the election not been revoked.

Initial Tax Basis and Amortization

The initial tax basis of the portion of the PDP Royalty Interest treated as a royalty interest in minerals and the portion treated as a production payment, and the initial basis of the portion of the PUD Royalty Interest treated as a royalty interest in minerals and the portion treated as a production payment will be effectively equal on a per-unit basis to the portion of the unit price allocated to each based on each such portion’s relative fair market value.

The costs incurred in selling the trust units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon the trust’s termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by the trust, and as syndication expenses, which may not be amortized by the trust. The underwriting discounts and commissions the trust incurs will be treated as syndication expenses.

Valuation and Tax Basis of the Trust’s Properties

The federal income tax consequences of the ownership and disposition of trust units will depend in part on the trust’s estimates of the relative fair market values, and the initial tax bases, of the trust’s assets. Although the trust may from time to time consult with professional appraisers regarding valuation matters, the trust will make many of the relative fair market value estimates itself. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by trust unitholders might change, and trust unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

DISPOSITION OF TRUST UNITS

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of trust units equal to the difference between the amount realized and the trust unitholder’s tax basis for the trust units sold. A trust unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received. The amount realized should be reduced by the unused net negative adjustments attributable to the trust units disposed of as described above under “— Tax Consequences of Trust Unit Ownership — Tax Treatment of the Term Royalties.” A trust unitholder’s adjusted tax basis in his trust units will be equal to the trust unitholder’s original

107

purchase price for the trust units, increased by income and decreased by losses or deductions previously allocated to the trust unitholder and by distributions to the trust unitholder and depletion deductions claimed by the trust unitholder.

Prior distributions from the trust in excess of cumulative net taxable income for a trust unit that decreased a unitholder’s tax basis in that trust unit will, in effect, become taxable income if the trust unit is sold at a price greater than the trust unitholder’s tax basis in that trust unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a trust unitholder, other than a “dealer” in trust units, on the sale or exchange of a trust unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of trust units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion, which will likely be substantial, of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to “unrealized receivables” the trust owns. The term “unrealized receivables” includes potential recapture items, including depletion recapture. Ordinary income attributable to unrealized receivables such as depletion recapture may exceed net taxable gain realized upon the sale of a trust unit and may be recognized even if there is a net taxable loss realized on the sale of a trust unit. Thus, a trust unitholder may recognize both ordinary income and a capital loss upon a sale of trust units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling trust unitholder who can identify trust units transferred with an ascertainable holding period to elect to use the actual holding period of the trust units transferred. Thus, according to the ruling discussed above, a trust unitholder will be unable to select high or low basis trust units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific trust units sold for purposes of determining the holding period of trust units transferred. A trust unitholder electing to use the actual holding period of trust units transferred must consistently use that identification method for all subsequent sales or exchanges of trust units. A trust unitholder considering the purchase of additional trust units or a sale of trust units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

108


	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, the trust’s taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the trust unitholders in proportion to the number of trust units owned by each of them as of the opening of the applicable exchange on which the trust units are then traded on the first business day of the month, which is referred to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of the trust’s assets other than in the ordinary course of business will be allocated among the trust unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a trust unitholder transferring trust units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code, and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee trust unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the trust unitholder’s interest, the trust’s taxable income or losses might be reallocated among the trust unitholders. The trust is authorized to revise its method of allocation between transferor and transferee trust unitholders, as well as trust unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A trust unitholder who owns trust units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of the trust’s income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A trust unitholder who sells any of his trust units is generally required to notify the trust in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of trust units who purchases trust units from another trust unitholder is also generally required to notify the trust in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, the trust is required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify

109

the trust of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who affects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

The trust will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in the trust’s capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of the trust’s taxable year for all trust unitholders. In the case of a trust unitholder reporting on a taxable year other than a calendar year, the closing of the trust’s taxable year may result in more than twelve months of the trust’s taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in the trust filing two tax returns (and trust unitholders may receive two Schedule K-1’s) for one fiscal year and the cost of the preparation of these returns will be borne by all trust unitholders. The trust would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code. A termination could also result in penalties if the trust was unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject the trust to, any tax legislation enacted before the termination.

TAX EXEMPT ORGANIZATIONS AND OTHER INVESTORS

Ownership of trust units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If a potential investor is a tax-exempt entity or a non-U.S. person, then it should consult a tax advisor before investing in the trust units.

Tax Exempt Organizations

Employee benefit plans and most other organizations exempt from federal income tax including IRAs and other retirement plans are subject to federal income tax on unrelated business taxable income. Because all of the income of the trust is expected to be royalty income, interest income, hedging income and gain from the sale of real property, none of which is unrelated business taxable income, any such organization exempt from federal income tax is not expected to be taxable on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are debt-financed property within the meaning of Section 514(b) of the Internal Revenue Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.

Non-U.S. Persons

The trust will be required to withhold (at a 30% rate or lower applicable treaty rate) on interest and royalty income allocable to non-U.S. trust unitholders.

Moreover, each of the PDP and PUD Royalty Interests will be treated as a “United States real property interest” for U.S. federal income tax purposes. However, as long as the trust units are

110

regularly traded on an established securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will be subject to federal income tax only if:


	•	the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder;

	•	the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions are met; or

	•	the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the trust units.

ADMINISTRATIVE MATTERS

Trust Information Returns and Audit Procedures

The trust intends to furnish to each trust unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of the trust’s income, gain, loss and deduction for the trust’s preceding taxable year. In preparing this information, which will not be reviewed by counsel, the trust will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each trust unitholder’s share of income, gain, loss and deduction. The trust cannot assure unitholders that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither the trust nor Vinson & Elkins L.L.P. can assure prospective trust unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit the trust’s federal income tax information returns. Adjustments resulting from an IRS audit may require each trust unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a trust unitholder’s return could result in adjustments not related to the trust’s returns as well as those related to the trust’s returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The trust agreement names ECA as the trust’s Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on behalf of the trust and the trust unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against trust unitholders for items in the trust’s returns. The Tax Matters Partner may bind a trust unitholder with less than a 1% profits interest in the trust to a settlement with the IRS unless that trust unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the trust unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any trust unitholder having at least a 1% interest in profits or by any group of trust unitholders having in the aggregate at least a 5% interest in profits. However, only one action for

111

judicial review will go forward, and each trust unitholder with an interest in the outcome may participate.

A trust unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on the trust’s return. Intentional or negligent disregard of this consistency requirement may subject a trust unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in the trust as a nominee for another person are required to furnish to the trust:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

1. a person that is not a United States person;

2. a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

3. a tax-exempt entity;

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to the trust. The nominee is required to supply the beneficial owner of the trust units with the information furnished to the trust.

Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

112

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of trust unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, the trust must disclose the pertinent facts on its return. In addition, the trust will make a reasonable effort to furnish sufficient information for trust unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit trust unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which the trust does not believe includes it, or any of the trust’s investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). The penalty is increased to 40% in the event of a gross valuation misstatement. The trust does not anticipate making any valuation misstatements.

Reportable Transactions

If the trust were to engage in a “reportable transaction,” the trust (and possibly the unitholders) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. The trust’s participation in a reportable transaction could increase the likelihood that the trust’s federal income tax information return (and possibly the unitholders’ tax return) would be audited by the IRS. Please read “— Trust Information Returns and Audit Procedures.”

Moreover, if the trust were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties”;

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

	•	in the case of a listed transaction, an extended statute of limitations.

The trust does not expect to engage in any “reportable transactions.”

113

STATE TAX CONSIDERATIONS

The following is intended as a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. Trust unitholders are urged to consult their own legal and tax advisors with respect to these matters.

Prospective investors should consider state and local tax consequences of an investment in the common units. The trust will own the royalty interests burdening specified gas properties located in Greene County, Pennsylvania. The state of Pennsylvania has income taxes applicable to individuals, but currently does not require the trust to withhold taxes from distributions made to nonresident unitholders. If withholding were required under current Pennsylvanian law, the rate would be 3.07% of taxable income attributable to Pennsylvania. A trust unitholder may be required to file state income tax returns and/or pay taxes in Pennsylvania and may be subject to penalties for failure to comply with such requirements. Taxes withheld by the trust would be treated as deductions against state income taxes otherwise payable.

The trust units may constitute real property or an interest in real property under the inheritance, estate and probate laws of Pennsylvania.

114

ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended, regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of a qualified plan should carefully consider fiduciary standards under ERISA regarding the qualified plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:


	•	whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

	•	whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment is in accordance with the documents and instruments governing the qualified plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in common units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not a qualified plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. ECA expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue Code Section 4975.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential qualified plan investors should consult with their counsel to determine the consequences under ERISA and the Internal Revenue Code of their acquisition and ownership of trust units.

115

SELLING TRUST UNITHOLDER

Prior to the closing of the offering made hereby, ECA will convey the royalty interests to the trust in exchange for cash, 3,186,117 common units and 4,500,000 subordinated units. Additionally, at the closing of this offering, ECA will purchase from the Private Investors a total of 209,316 common units at the initial offering price. If the underwriters exercise the option to purchase an additional 1,350,000 common units at the initial public offering price, then ECA will offer 1,350,000 of its common units to cover the over-allotment option of those common units. ECA and the Private Investors have agreed, however, not to sell any trust units for period of 180 days after the date of this prospectus without the prior written consent of Raymond James & Associates, Inc. and Citigroup Global Markets Inc. acting as representatives of the several underwriters, subject to specified exceptions and other than the sale of common units to ECA by the Private Investors. See “Underwriting.”

The following table provides information regarding the selling trust unitholder’s ownership of the trust units. This table assumes the underwriters’ over-allotment option is exercised.

Ownership of Trust Units

Ownership of

After Offering (Assuming

Trust Units

Full Exercise

Before Exercise

Number of

of Underwriters’

of Underwriters’ Over-Allotment Option

Common Units

Over-Allotment)

Selling Trust Unitholder

Number

Percentage

Being Offered

Number

Percentage

Energy Corporation of America

7,895,433

43.9%

1,350,000

6,545,433

36.4%

Prior to this offering there has been no public market for the common units. Therefore, if ECA disposes of its remaining trust units, it cannot predict the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.

116

UNDERWRITING

Subject to the terms and conditions in an underwriting agreement dated , 2010, the underwriters named below, for whom Raymond James & Associates, Inc. and Citigroup Global Markets Inc. are acting as representatives, have severally agreed to purchase from ECA the common of trust units set forth opposite their names:


	Number of
Name of Underwriter	Common Units

Raymond James & Associates, Inc.
Citigroup Global Markets Inc.

Total		9,000,000

The underwriting agreement provides that the obligations of the underwriters to purchase and accept delivery of the common units offered by this prospectus are subject to the satisfaction of the conditions contained in the underwriting agreement, including:


	•	the representations and warranties made by ECA to the underwriters are true;

	•	there is no material adverse change in the financial market; and

	•	ECA delivers customary closing documents and legal opinions to the underwriters.

The underwriters are obligated to purchase and accept delivery of all of the trust units offered by this prospectus, if any of the units are purchased, other than those covered by the option to purchase additional common units described below.

The underwriters propose to offer the common units directly to the public at the public offering price indicated on the cover page of this prospectus and to various dealers at that price less a concession not in excess of $ per unit. If all of the common units are not sold at the public offering price, the underwriters may change the public offering price and other selling terms. The common units are offered by the underwriters as stated in this prospectus, subject to receipt and acceptance by them. The underwriters reserve the right to reject an order for the purchase of the common units in whole or in part.

OPTION TO PURCHASE ADDITIONAL COMMON UNITS

The trust has granted the underwriters an option, exercisable for 30 days after the date of this prospectus, to purchase from time to time up to an aggregate of 1,350,000 additional common units to cover over-allotments, if any, at the public offering price less the underwriting discounts and commissions set forth on the cover page of this prospectus. The net proceeds of any exercise of the underwriters’ over-allotment option will be used to redeem an equal number of common units held by ECA. If the underwriters exercise this option, each underwriter, subject to certain conditions, will become obligated to purchase its pro rata portion of these additional units based on the underwriters’ percentage purchase commitment in this offering as indicated in the table above. The underwriters may exercise the option to purchase additional common units only to cover over-allotments made in connection with the sale of the common units offered in this offering.

117

DISCOUNTS AND EXPENSES

The following table shows the amount per unit and total underwriting discounts ECA will pay to the underwriters (dollars in thousands, except per unit). The amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

Total without

Total with

Over-Allotment

Per Unit

Exercise

Price to the public

Underwriting discount and commissions

Proceeds, to the trust (before expenses)

The other expenses of this offering that are payable by the trust are estimated to be $ million (exclusive of underwriting discounts and commissions).

INDEMNIFICATION

ECA has agreed to indemnify the underwriters and persons who control the underwriters against certain liabilities that may arise in connection with this offering, including liabilities under the Securities Act of 1933 and liabilities arising from breaches of representations and warranties contained in the underwriting agreement.

LOCK-UP AGREEMENTS

Subject to specified exceptions, including the sale of 209,316 common units to ECA by the Private Investors at the closing of this offering, ECA and the Private Investors have agreed with the underwriters, for a period of 180 days after the date of this prospectus, without the prior written consent of Raymond James & Associates, Inc. and Citigroup Global Markets Inc.:


	•	not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units;

	•	not to grant or sell any option or contract to purchase any of the trust units;

	•	not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the trust units; and

	•	not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the trust units, whether or not such transfer would be for any consideration.

These agreements also prohibit ECA and the Private Investors from entering into any of the foregoing transactions with respect to any securities that are convertible into or exchangeable for the trust units.

Raymond James & Associates, Inc. and Citigroup Global Markets Inc. may, in their discretion and at any time without notice, release all or any portion of the securities subject to these agreements. Raymond James & Associates, Inc. and Citigroup Global Markets Inc. do not have any

118

present intent or any understanding to release all or any portion of the securities subject to these agreements.

The 180-day period described in the preceding paragraphs will be extended if:


	•	during the last 17 days of the 180-day period, the trust issues a release concerning distributable cash or announces material news or a material event relating to the trust occurs; or

	•	prior to the expiration of the 180-day period, the trust announces that it will release distributable cash results during the 16-day period beginning on the last day of the 180-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event.

STABILIZATION

Until this offering is completed, rules of the SEC may limit the ability of the underwriters and various selling group members to bid for and purchase the common units. As an exception to these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of the common units, including:


	•	short sales,

	•	syndicate covering transactions,

	•	imposition of penalty bids, and

	•	purchases to cover positions created by short sales.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the common units while this offering is in progress. Stabilizing transactions may include making short sales of common units, which involve the sale by the underwriters of a greater number of common units than it is required to purchase in this offering and purchasing common units from ECA or in the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

Each underwriter may close out any covered short position either by exercising its option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, each underwriter will consider, among other things, the price of common units available for purchase in the open market compared to the price at which the underwriter may purchase common units pursuant to the option to purchase additional common units.

A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering. To the extent that the underwriters create a naked short position, they will purchase common units in the open market to cover the position.

119

The underwriters also may impose a penalty bid on selling group members. This means that if the underwriters purchase common units in the open market in stabilizing transactions or to cover short sales, the underwriters can require the selling group members that sold those common units as part of this offering to repay the selling concession received by them.

As a result of these activities, the price of the common units may be higher than the price that otherwise might exist in the open market. If the underwriters commence these activities, they may discontinue them without notice at any time. The underwriters may carry out these transactions on the New York Stock Exchange or otherwise.

CONFLICTS/AFFILIATES

Certain of the underwriters and their affiliates may provide in the future investment banking, financial advisory or other financial services for ECA and its affiliates, for which they may receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and in amounts customary in the industry for these financial services.

DISCRETIONARY ACCOUNTS

The underwriters may confirm sales of the common units offered by this prospectus to accounts over which they exercise discretionary authority but do not expect those sales to exceed 5% of the total common units offered by this prospectus.

LISTING

The common units have been approved for listing on the New York Stock Exchange under the symbol “ECT,” subject to official notice of issuance. In connection with the listing of the common units on the New York Stock Exchange, the underwriters will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.

DETERMINATION OF INITIAL OFFERING PRICE

Prior to this offering, there has been no public market for the common units. Consequently, the initial public offering price for the common units will be determined by negotiations among ECA and the underwriters. The primary factors to be considered in determining the initial public offering price will be:


	•	estimates of distributions to trust unitholders,

	•	overall quality of the natural gas properties attributable to the Underlying Properties,

	•	industry and market conditions prevalent in the energy industry,

	•	the information set forth in this prospectus and otherwise available to the representatives, and

	•	the general conditions of the securities markets at the time of this offering.

The initial offering price may not correspond to the price at which the common units will trade in the public market subsequent to this offering, and an active trading market may develop and continue after this offering.

120

ELECTRONIC PROSPECTUS

A prospectus in electronic format may be available on the Internet sites or through other online services maintained by one or more of the underwriters and selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the underwriter or the selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with ECA to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the underwriters on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or any selling group member’s website and any information contained in any other website maintained by the underwriters or any selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by ECA or any underwriters or any selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

FINRA RULES

Because the Financial Industry Regulatory Authority, or the “FINRA” is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

121

CERTAIN TRANSACTIONS

Certain officers, directors and employees of ECA and members of their families (the “Private Investors”) regularly participate in ECA’s annual drilling programs. Under such drilling programs, ECA has the right to select the wells to be drilled, and the Private Investors cannot selectively choose the wells in which they participate. For so long as (i) a Private Investor remains a director or employee of ECA (or, in the case of a family member, for so long as the family member remains a director or employee of ECA) and (ii) such Private Investor has participated in the prior year’s drilling program, such Private Investor has the right to participate in ECA’s future drilling programs. The Private Investors listed below participated in ECA’s 2009 drilling program (the “Drilling Program”), and based on the success of this program, are entitled to participate in future drilling programs.

The following table sets forth with respect to those Private Investors that are beneficial holders of more than 5% of either class of ECA’s securities, directors of ECA or executive officers of ECA, and their immediate family members; all other Private Investors as a group; and all the Private Investors as a group: (i) the purchase price paid by such Private Investor for his or her interest in the Drilling Program and (ii) such Private Investor’s percentage interest in the Drilling Program.


	Purchase Price for		Percentage
	Participation		Interest in the
	in Drilling		Drilling
Private Investors	Program		Program

W. Gaston Caperton, III	$	116,259		1.89%
Peter H. Coors		290,646		4.72%
L.B. Curtis		67,430		1.10%
John J. Dorgan		58,129		0.94%
John S. Fischer		290,646		4.72%
Michael S. Fletcher		29,065		0.47%
J. Michael Forbes		40,458		0.66%
Thomas R. Goodwin		174,388		2.83%
F.H. McCullough III (1)		453,408		7.36%
John Mork (2)		3,573,790		58.05%
Julie M. Mork (2)		3,573,790		58.05%
Kyle M. Mork (3)		337,150		5.48%
Arthur C. Nielsen, Jr.		29,065		0.47%
George O’Malley		29,669		0.48%
Jay S. Pifer		29,065		0.47%
Donald C. Supcoe		58,129		0.94%

	$	5,577,297		90.59%
Other Private Investors		549,043		8.92%

Private Investor Total	$	6,126,339		99.51%


(1)		Includes investments by the Katherine F. McCullough Trust, the Lesley McCullough Trust, the Kristin McCullough Trust and the Meredith McCullough Trust.


(2)		Includes investments by John and Julie Mork as joint tenants, and investments by the Alison Mork Trust.


(3)		Includes investments by the Kyle Mork Trust.

Immediately prior to the closing of this offering, the Private Investors will convey to ECA the working interest each such Private Investor holds in the Producing Wells, retaining a perpetual royalty interest identical in nature to the Perpetual PDP Royalty to be contributed by ECA to the

122

trust (individually, a “Private Investor Royalty” and collectively, the “Private Investors Royalties”). At the closing of this offering, the Private Investors will convey the Private Investors Royalties to the trust and agree to forgo his or her ability to participate in future drilling programs with respect to the portion of PUD Wells being conveyed to the trust in exchange for the common units described below. Certain Private Investors have elected for ECA to purchase at the closing of the offering a portion of their common units to be received as described above at the initial public offering price. Pursuant to such election, ECA will purchase a total of 209,316 common units from the Private Investors at the closing of this offering. Upon completion of the transactions described above, ECA will hold 3,395,433 common units (2,045,433 if the underwriters exercise their over-allotment option in full) and 4,500,000 subordinated units, representing 43.9% of the trust units (36.4% if the underwriters exercise their over-allotment option in full), and the Private Investors will hold 1,104,567 common units, representing 6.1% of the trust units.

The table below sets forth with respect to those Private Investors that are beneficial holders of more than 5% of either class of ECA’s securities, directors of ECA or executive officers of ECA, and their immediate family members; all other Private Investors and all Private Investors as a group: (i) the value of the Private Investor’s interest in the Drilling Program, including relinquishment of the right to participate in the portion of the PUD Wells being conveyed to the trust; (ii) the Private Investor’s percentage interest in the Drilling Program; (iii) the number of common units to be owned by the Private Investor after the purchase by ECA of a portion of the common units as described above; and (iv) the cash proceeds to be received by such Private Investor upon the purchase by ECA of such common units.


					Number of		Cash Proceeds
	Value of		Percentage		Common Units		Upon Sale to
	Interest in the		Interest in the		After Purchase		ECA of
Private Investors	Drilling Program		Drilling Program (1)		by ECA		Common Units

W. Gaston Caperton, III	$	496,209		1.89%		24,933	$
Peter H. Coors		1,240,522		4.72%		62,333
L.B. Curtis		287,801		1.10%		13,000
John J. Dorgan		248,104		0.94%		12,467
John S. Fischer		1,240,522		4.72%		56,100
Michael S. Fletcher		124,052		0.47%		3,233
J. Michael Forbes		172,681		0.66%		8,677
Thomas R. Goodwin		744,314		2.83%		37,400
F.H. McCullough III (2)		1,935,215		7.36%		78,000
John Mork (3)		15,253,477		58.05%		616,451
Julie M. Mork (3)		15,253,477		58.05%		616,451
Kyle M. Mork (4)		1,439,007		5.48%		72,307
Arthur C. Nielsen, Jr.		124,052		0.47%		6,233
George O’Malley		126,633		0.48%		2,000
Jay S. Pifer		124,052		0.47%		6,233
Donald C. Supcoe		248,104		0.94%		6,234

	$	23,804,748		90.59%		1,005,601	$
Other Private Investors		2,343,397		8.92%		98,966

Private Investor Total	$	26,148,144		99.51%		1,104,567	$

123


(1)		At the closing of this offering, each Private Investor will retain an identical percentage ownership in the Drilling Program. However, the size of the Drilling Program will have been reduced following the conveyances of the Private Investors Royalties due to the Private Investors foregoing their ability to participate in future drilling programs with respect to the royalty interest in the PUD Wells being conveyed to the trust. Accordingly, the total value of each Private Investor’s interest in the Drilling Program will have been reduced, despite such Private Investor retaining the same percentage interest in the Drilling Program.


(2)		Includes investments by the Katherine F. McCullough Trust, the Lesley McCullough Trust, the Kristin McCullough Trust and the Meredith McCullough Trust.


(3)		Includes investments by John and Julie Mork as joint tenants, and investments by the Alison Mork Trust.


(4)		Includes investments by the Kyle Mork Trust.

124

LEGAL MATTERS

, as special Delaware counsel to ECA, will give a legal opinion as to the validity of the trust units. Vinson & Elkins L.L.P., Houston, Texas, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “Federal income tax considerations.” Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

Certain information appearing in this prospectus regarding the March 31, 2010 estimated quantities of reserves of the Underlying Properties and royalty interests owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Ryder Scott Company, L.P., independent petroleum engineers.

The consolidated financial statements of Energy Corporation of America as of June 30, 2009 and 2008 and for each of three years in the period ended June 30, 2009 and the statement of historical revenues and direct operating expenses of the Underlying PDP Properties, for the period ended December 31, 2009 appearing in this prospectus have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

The statement of assets and trust corpus of ECA Marcellus Trust I as of March 19, 2010, included in this Registration Statement has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report appearing elsewhere herein, and is included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

The trust and ECA have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding the trust, ECA and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The trust’s and ECA’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish the trust’s unitholders annual reports containing our audited consolidated financial statements and to furnish or make available to the trust’s unitholders quarterly reports containing the trust’s unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

125

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST

In this prospectus the following terms have the meanings specified below.

AMI — The Marcellus Shale formation of the proved undeveloped natural gas properties presently consisting of approximately 9,300 net acres held by ECA excluding existing well bores on which ECA has agreed to drill PUD Wells for the benefit of the trust by March 31, 2013 subject to a one year extension to complete drilling in the case of delays. The AMI will consist of approximately 121 square miles and is depicted by the area identified on the inside front cover of this prospectus.

Bbl — One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf — One billion standard cubic feet of natural gas.

Bcfe — One billion standard cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf.

Btu — A British Thermal Unit, a common unit of energy measurement.

ECA’s retained interest — ECA’s retained interest in 10% of the proceeds from the sale of production from the 14 producing Marcellus Shale natural gas wells located in Greene County, Pennsylvania as well as ECA’s retained interest in 50% of the proceeds from the sale of production from the PUD Wells to be drilled in the AMI.

Estimated future net revenues — Also referred to as “estimated future net cash flows.” The result of applying current prices of natural gas to estimated future production from natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Farmout agreement — A farmout agreement is typically an agreement under which a lessee under an oil and gas lease agrees to grant to another party the right to drill wells on the tract covered by such lease and to earn certain acreage for drilling such wells.

Fractional well — Wells with a horizontal lateral (measured from the midpoint of the curve) of less than 2,500 feet in proportion to total length divided by 2,500 count as fractional wells while wells with a horizontal lateral of more than 2,500 feet in proportion to total lateral length divided by 2,500 count as multiple fractional wells.

MBbl — One thousand Bbl.

Mcf — One thousand standard cubic feet of natural gas.

Mcfe — One thousand standard cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf.

MMBtu — One million British Thermal Units (Btus).

MMcf — One million standard cubic feet of natural gas.

126

MMcfe — One million standard cubic feet of natural gas equivalent, computed on an approximate energy equivalent basis that one Bbl equals six Mcf.

Net Profits Interest — A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

PDP Royalty Interest — royalty interests entitling the trust to receive an aggregate of 90% of the proceeds (net of post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s working interest in the 14 producing horizontal Marcellus Shale natural gas wells located in Greene County, Pennsylvania for 20 years, and 45% of such proceeds thereafter (pending a sale thereof by the trust).

Proved developed reserves — Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves — The estimated quantities of natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known natural gas reservoirs under existing economic and operating conditions.

The Securities and Exchange Commission definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in

127

undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved undeveloped reserves — Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

PUD Royalty Interest — royalty interests entitling the trust to receive an aggregate of 50% of the proceeds (net of post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in 52 horizontal Marcellus Shale natural gas wells to be drilled in the AMI and 25% of such proceeds thereafter (pending a sale thereof by the trust).

Tcf — One trillion standard cubic feet of natural gas.

Working interest — A property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and certain activities in connection with the development and operation of a property.

128

INDEX TO FINANCIAL STATEMENTS

TABLE OF CONTENTS


UNDERLYING PDP PROPERTIES
Report of Independent Registered Public Accounting Firm			F-2
Statement of Historical Revenues and Direct Operating Expenses for the Six Months Ended December 31, 2009			F-3
Notes to the Statement of Historical Revenues and Direct Operating Expenses			F-4
ECA MARCELLUS TRUST I			F-8
Report of Independent Registered Public Accounting Firm			F-8
Statement of Assets and Trust Corpus			F-9
Notes to Statement of Assets and Trust Corpus			F-10

F-1

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders
Energy Corporation of America:

We have audited the accompanying statement of historical revenues and direct operating expenses of the Underlying Properties (the “Properties”) of Energy Corporation of America (“the Company”) for the six month period ended December 31, 2009. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of historical revenues and direct operating expenses of the Properties is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of historical revenues and direct operating expenses, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement of historical revenues and direct operating expenses presentation. We believe that our audit provides a reasonable basis for our opinion.

The accompanying statement was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in the notes to the financial statement and is not intended to be a complete presentation of the Company’s interests in the Properties.

In our opinion, the statement referred to above presents fairly, in all material respects, the historical revenues and direct operating expenses of the Properties for the six month period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 12, 2010

F-2

UNDERLYING PROPERTIES
STATEMENT OF HISTORICAL REVENUES AND DIRECT OPERATING EXPENSES
For the Six Months Ended December 31, 2009


	(In thousands)

Revenues:
Gas Sales	$	3,623

Total Revenues		3,623
Operating Expenses:
Taxes on Production and Property		—
Lease Operation Expenses		22
Field Operation Expenses		2
Marketing Fee		132
Gathering and Transportation		458

Total Operating Expenses		614

Excess of revenues over operating expenses	$	3,009

See accompanying notes to the Statement of Historical Revenues and Direct Operating Expenses.

F-3

UNDERLYING PROPERTIES

Notes to the Statement of Historical Revenues and
Direct Operating Expenses

FOR THE SIX MONTHS ENDED DECEMBER 31, 2009


1.	PROPERTIES

The Underlying Properties (“Properties”) consist of the working interests owned by Energy Corporation of America and the Private Investors in the Marcellus Shale formation in Greene County, Pennsylvania arising under leases and farmout agreements from which the PDP Royalty Interest and the PUD Royalty Interest will be conveyed. As of December 31, 2009 the Properties consisted of four producing wells, the first of which began production on July 17, 2009, three proved behind pipe wells, and 59 horizontal natural gas development wells to be drilled to the Marcellus Shale formation within the Area of Mutual Interest, which is comprised of approximately 9,300 net acres held by ECA in Greene County, Pennsylvania.

Eastern Marketing Corporation, a wholly owned subsidiary of ECA, has purchased the natural gas production from these wells at prices substantially equivalent to prices paid by unaffiliated purchasers in the marketing area.


2.	BASIS OF PRESENTATION

The accompanying statement of historical revenues and direct operating expenses was derived from the historical accounting records of ECA and reflects the historical revenues and operating expenses directly attributable to the Underlying Properties for the period described herein. Such amounts may not be representative of future operations. The statement does not include depreciation, depletion and amortization, general and administrative expenses, interest expense, federal and state income taxes or other expenses of an indirect nature. The amounts represent 100% of ECA’s and the Private Investors’ interest.

Historical financial statements reflecting financial position, results of operations and cash flows required by generally accepted accounting principles are not presented as such information is not readily available on an individual property basis and not meaningful to the Underlying Properties. Accordingly, the statement of historical revenue and direct operating expenses is presented in accordance with Staff Accounting Bulletin Topic 2-D, Financial Statements of Oil and Gas Exchange Offers.

The accompanying statement of historical revenues and direct operating expenses included herein was prepared on an accrual basis. Revenue from gas sales is recognized when the gas is produced and sold.

The process of preparing the financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions regarding certain types of revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.


3.	SUPPLEMENTAL INFORMATION ON GAS PRODUCING ACTIVITIES (UNAUDITED)

Information with respect to gas producing activities of the Underlying Properties is presented in the following tables. The information was derived from reserve reports which were prepared

F-4

UNDERLYING PROPERTIES

Notes to the Statement of Historical Revenues and
Direct Operating Expenses — (Continued)

by independent reserve engineers as of December 31, 2009, in accordance with ASU 2010-03 “Extractive Activities — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures.”

Gas Reserves

Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

The following table summarizes the estimated quantities of the proved natural gas reserves (MMcfs) of the Underlying Properties:


	Natural Gas
	(Mmcf)

Proved reserves:
June 30, 2009		—

Revisions of previous estimates		—
Extensions and discoveries		195,214
Sales of reserves in place		—
Purchases of reserves in place		—
Production		(841	)

December 31, 2009		194,373

Proved developed reserves:
December 31, 2009		9,664

Proved reserves are estimated quantities of natural gas which geological and engineering data indicated with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions. Proved developed reserves are proven reserves, which are expected to be recovered through existing wells with existing equipment and operation methods.

Estimated Present Value of Future Net Cash Flows

Standardized Measure of Discounted Future Net Cash Flows — Estimated discounted future net cash flows and changes therein were determined in accordance with ASC 932, “Disclosures About Oil and Gas Producing Activities.” Certain information concerning the assumptions used in computing the valuation of proved developed reserves and their inherent limitations are discussed below. ECA believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying the average prices of gas during the 12-month period ending December 31, 2009, determined using the unweighted arithmetic average of the prices in effect on the first-day-of-the-month for each month within the period relating to the Underlying Properties proved reserves to the period-end quantities of those reserves. Future price

F-5

UNDERLYING PROPERTIES

Notes to the Statement of Historical Revenues and
Direct Operating Expenses — (Continued)

changes are considered only to the extent provided by contractual arrangements in existence at period-end.

The assumptions used to compute estimated future net revenues do not necessarily reflect ECA’s expectations of actual revenues or costs or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of ECA’s control, such as unintentional delays in development, changes in prices or regulatory controls. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at December 31, 2009, based on period-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate period-end statutory tax rates and existing tax credits, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the Underlying Properties proved gas reserves.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved developed gas reserves in accordance with the rules and regulations of the SEC.

Information with respect to the Underlying Properties estimated discounted future net cash flows related to its proved gas reserves as of December 31, 2009 is as follows (in thousands):


	2009

Future cash in flows	$	774,788
Future production and development costs		(332,616	)
Future income tax expense		(172,000	)

Future net cash flows before discount		270,172
10% discount to present value		(192,146	)

Standardized measure of discounted future net cash flows related to proved oil and gas reserves	$	78,026

F-6

UNDERLYING PROPERTIES

Notes to the Statement of Historical Revenues and
Direct Operating Expenses — (Continued)

The changes in the standardized measure of discounted future net cash flows relating to proved gas reserves as of December 31, 2009 is as follows (in thousands):


	2009

Standardized measure of discounted future net cash flow at beginning of period	$	—
Sales of oil and gas produced, net of production costs		(3,009	)
Net changes in prices and production costs		—
Changes in production rates and other		—
Extensions, discoveries and other additions, net of future production and development costs		75,460
Changes in estimated future development costs		—
Development costs incurred		5,575
Revisions of previous quantity estimates		—
Purchase of reserves in place		—
Accretion of discount		—
Net change in income taxes		—

Standardized measure of discounted future net cash flows at end of period	$	78,026

F-7

ECA MARCELLUS TRUST I

Report of Independent Registered Public Accounting Firm

To the Trustee
ECA Marcellus Trust I:

We have audited the accompanying statement of assets and trust corpus of ECA Marcellus Trust I (the “Trust”) as of March 19, 2010. This financial statement is the responsibility of the Trust’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of assets and trust corpus is free of material misstatement. We were not engaged to perform an audit of the Trust’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Trust’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement of assets and trust corpus presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note 2 to the statement of assets and trust corpus, this statement has been prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

In our opinion, the statement of assets and trust corpus presents fairly, in all material respects, the financial position of ECA Marcellus Trust I as of March 19, 2010, on the basis of accounting described in Note 2.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 22, 2010

F-8

ECA MARCELLUS TRUST I

Statement of Assets and Trust Corpus


	As of
	March 19, 2010

Assets:
Cash	$	10

Total	$	10

Trust Corpus:
Trust corpus	$	10

Total	$	10

See notes to the statement of assets and trust corpus.

F-9

ECA MARCELLUS TRUST I

Notes to Statement of Assets and Trust Corpus


1.	ORGANIZATION OF THE TRUST

The ECA Marcellus Trust I (“the Trust”) is a statutory trust formed in March 2010 under the Delaware Statutory Trust Act pursuant to a Trust Agreement (the “Trust Agreement”) among Energy Corporation of America (“ECA”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”).

The Trust was created to acquire and hold royalty interests for the benefit of Trust unitholders pursuant to an agreement between ECA, the Trustee and the Delaware Trustee. These royalty interests are interests in underlying producing properties consisting of ECA’s interests in specified gas properties located in the Marcellus Shale Formation in Greene County, Pennsylvania. These properties consist of four producing wells, the first of which began production on July 17, 2009, three proved behind pipe wells, and 59 horizontal natural gas development wells to be drilled to the Marcellus Shale formation within the area of mutual interest, which is comprised of approximately 9,300 net acres held by ECA in Greene County, Pennsylvania.

The royalty interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. After the conveyance of royalty interests, ECA will retain interest in each of the Underlying PDP Properties and Underlying PUD Properties. The trust agreement will provide that the Trust’s business activities will be limited to owning the royalty interests and any activity reasonably related to such ownership including activities of a portion of certain natural gas floor price contracts which relate to a portion of the natural gas production attributable to the trust’s royalty interest. The Trust will not be permitted to acquire other oil and gas properties or royalty interests.

The Trust will begin to liquidate on March 31, 2030 (the “Termination Date”) and will soon thereafter wind up its affairs and terminate. Fifty percent of the royalty interests will automatically revert to ECA at the Termination Date, while the Perpetual Royalties will be sold and the proceeds will be distributed to the unitholders at the Termination Date or soon thereafter. ECA will have a first right of refusal to purchase the remaining fifty percent of the royalty interests at the Termination Date.


2.	SIGNIFICANT ACCOUNTING POLICIES

The following is a summary of the significant accounting policies followed by the Trust.

Basis of Accounting — The financial statements of the Trust are prepared on the following basis:


	•	Royalty income recorded is the amount computed to be paid by ECA to the Trustee on behalf of the Trust for the corresponding quarter.

	•	Trust expenses are recorded when paid.

	•	Distributable income is reduced by cash reserves established for liabilities and contingencies.

	•	Distributions to unitholders are recorded in the quarter to which they apply.

F-10

ECA MARCELLUS TRUST I

Notes to Statement of Assets and Trust Corpus — (Continued)

The financial statements of the trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) because certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to trust corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Cash — Cash consists of highly liquid instruments with maturities at the time of acquisition of three months or less.

Use of Estimates in the Preparation of Financial Statements — The preparation of financial statements requires the trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.


3.	INCOME TAXES

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes.


4.	DISTRIBUTIONS TO UNITHOLDERS

The trust will make quarterly cash distributions of the cash received from Energy Corporation of America, after deducting trust administrative expenses paid on or about 60 days after the completion of each quarter through (and including) the quarter ending March 31, 2030 (the “Termination Date”). The first quarterly distribution is expected to be made on or about August 31, 2010 to record unitholders as of August 15, 2010. The trust will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and terminate. Upon termination of the trust, 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty Interest and the PUD Royalty Interest will be sold, and the net proceeds therefrom will be distributed pro rata to the unitholders soon after the Termination Date. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent a return of your original investment.

F-11

ECA MARCELLUS TRUST I

Unaudited Pro Forma Financial Information

The following unaudited pro forma statement of asset and trust corpus and unaudited pro forma statements of distributable income for the Trust have been prepared to illustrate the conveyance of royalty interests in certain Underlying Properties to the trust by ECA. The unaudited pro forma statement of asset and trust corpus presents the beginning statement of assets, liabilities and trust corpus of the Trust as of March 19, 2010, giving effect to the royalty interests conveyance as if it occurred on that date. The unaudited pro forma statement of distributable income presents the statements of historical revenue and direct operating expenses of the Underlying PDP Properties for the six months ended December 31, 2009, giving effect to the royalty interests conveyance as if it occurred as of July 1, 2009, reflecting only pro forma adjustments expected to have a continuing impact on the combined results.

These unaudited pro forma financial statements are for informational purposes only. They do not purport to present the results that would have actually occurred had the royalty interests conveyance been completed on the assumed dates or for the periods presented, or which may be realized in the future.

To produce the pro forma financial information, management made certain estimates. The accompanying unaudited pro forma statement of assets, liabilities and trust corpus assumes a March 19, 2010 issuance of 18,000,000 trust units at $ per unit. The accompanying unaudited pro forma statements of distributable income for the six months ended December 31, 2009 have been prepared assuming Trust formation and royalty interests conveyance at the beginning of the period presented.

These estimates are based on the most recently available information. To the extent there are significant changes in these amounts, the assumptions and estimates herein could change significantly. The statements of distributable income should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Energy Corporation of America” included in the ECA Annex to this prospectus and the historical statements of the trust, ECA and the Underlying Properties, including the related notes, included in this prospectus.

F-12

ECA MARCELLUS TRUST I

Unaudited Pro Forma Statements of Assets, Liabilities, and Trust Corpus

As of March 19, 2010


	Historical		Adjustments			Pro Forma

Assets:
Cash	$	10	$	—		$	10
Investment in Royalty Interest		—		360,000,000	(a)		360,000,000
Floor price contracts		—		4,957,920	(a)		4,957,920

Total Assets	$	10	$	364,957,920		$	364,957,930

Liabilities:
Floor premiums payable	$	—	$	4,957,920	(b)	$	4,957,920

Total Liabilities	$	—	$	4,957,920		$	4,957,920
Trust Corpus:
18,000,000 Trust Units Issued and Outstanding at Formation	$	10	$	360,000,000		$	360,000,010

Total Liabilities and Trust Corpus	$	10	$	364,957,920		$	364,957,930

The accompanying notes are integral part of the unaudited pro forma financial information

F-13

ECA MARCELLUS TRUST I

Unaudited Pro Forma Statement of Distributable Income

For the Six Month Period Ended December 31, 2009

(In thousands, except per unit)


	Six Months Ended
	December 31,
	2009

Historical results:
Revenue from gas sales	$	3,623
Direct operating expenses:
Production and property taxes		—
Production expenses		24
Marketing fee		132
Gathering and transportation		458

Total		614

Excess of revenues over direct operating expenses before pro forma adjustments	$	3,009
Pro Forma adjustments:
Historical production expenses		24	(c)
Marketing fee		132	(c)

Total pro forma adjustments		156

Pro forma gross net proceeds	$	3,165
Overriding royalty interest percentage		90	%

Net proceeds to trust	$	2,849
Less trust general and administrative expenses and state franchise taxes		550	(d)

Distributable income	$	2,299	(e)

Distributable income per unit	$	0.13

The accompanying notes are integral part of the unaudited pro forma financial information

F-14

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information


NOTE 1.	BASIS OF PRESENTATION

ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation of America to own royalty interests in 14 producing horizontal natural gas wells producing from the Marcellus Shale formation and located in Greene County, Pennsylvania (the “Producing Wells”) and royalty interests in 52 horizontal natural gas development wells to be drilled in the Marcellus Shale formation (the “PUD Wells”) within the “area of mutual interest,” or “AMI”, comprised of approximately 9,300 net acres held by ECA in Greene County, Pennsylvania. The royalty interests will be conveyed from ECA’s working interest in the Producing Wells limited to the Marcellus Shale formation (approximately 93%) and the PUD Wells (the “underlying properties”). The royalty interest in the Producing Wells (the “PDP Royalty Interest”) entitles the trust to receive 90% of the proceeds (after deducting post-production costs and any applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the Producing Wells. The royalty interest in the PUD Wells (the “PUD Royalty Interest”) entitles the trust to receive 50% of the proceeds (after deducting post-production costs and applicable taxes) from the sale of production of natural gas attributable to ECA’s interest in the PUD Wells. Approximately 50% of the estimated natural gas production attributable to the trust’s royalty interests will be hedged from April 1, 2010 to March 31, 2014. These hedging contracts will be transferred to the trust by ECA, and ECA will be entitled to recoup the costs of establishing the hedging contracts to the extent cash available for distribution by the trust exceeds certain levels.

The unaudited pro forma financial information assumes the issuance of 18,000,000 trust units at $ per unit.

In order to provide support for cash distributions on the common units, ECA has agreed to subordinate 4,500,000 of the trust units it will retain following this offering, which will comprise 25% of the outstanding trust units. While the subordinated units will be entitled to receive pro rata distributions from the trust if and to the extent there is sufficient cash to provide a cash distribution on the common units which is no less than the applicable quarterly subordination threshold, if there is not sufficient cash to fund such a distribution on all trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. Each applicable quarterly subordination threshold is equal to 80% of the target cash distribution level for the corresponding quarter as reflected on Annex B (each, a “subordination threshold”). In exchange for agreeing to subordinate these trust units, and in order to provide additional financial incentive to ECA to perform its drilling obligation and operations in the Underlying Properties in an efficient and cost-effective manner, ECA will be entitled to receive incentive distributions (the “incentive distributions”) equal to 50% of the amount by which the cash available for distribution on all of the trust units in any quarter exceeds 150% of the subordination threshold for such quarter (which is 120% of the target cash distribution) (each, an “incentive threshold”). ECA’s right to receive this incentive distribution will terminate upon the expiration of the subordination period. Additionally and notwithstanding the foregoing, in exchange for the transfer by ECA to the trust of the natural gas hedging contracts, until the earlier of the expiration of the subordination period (as defined below) or such time as the costs associated with establishing the natural gas hedging contracts (the “reimbursement amount”) have been paid in full, the trust will pay ECA an amount equal to 50% of the amount by which the cash receipts in respect of the royalties in any quarter exceeds the applicable incentive threshold. Such obligation includes interest on the reimbursement amount accruing at 10% per

F-15

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information — (Continued)

year. ECA bears the risk that the subordination period will end before it is reimbursed in full for establishing the hedging contracts.

ECA has incurred costs of approximately $5 million in securing the hedging contracts to be transferred to the trust. ECA will be entitled to reimbursement for these expenditures only if and to the extent distributions to trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the trust unitholders. ECA’s right to receive the remaining 50% of such cash in the form of incentive distributions would not be affected.

The subordinated units will automatically convert into common units on a one-for-one basis and ECA’s right to receive incentive distributions and to recoup the reimbursement amount will terminate, at the end of the fourth full calendar quarter following ECA’s satisfaction of its drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or fully reimbursed for the hedging contracts it is transferring to the trust. The trust currently expects that ECA will complete this drilling obligation on or before March 31, 2013 and that, accordingly, the subordinated units will convert into common units on or before March 31, 2014. In the event of delays, ECA will have until March 31, 2014 to drill all the PUD Wells, in which event the subordinated units will convert into common units on or before March 31, 2015. The period during which the subordinated units are outstanding is referred to as the “subordination period.”


NOTE 2.	TRUST ACCOUNTING POLICIES

The Unaudited Pro Forma Statement of Distributable Income was derived from the historical accounting records of the Underlying Properties.

Income determined on the basis of generally accepted accounting principles would include all expenses incurred for the period presented. However, the Trust serves as a pass-through entity, with expenses for depreciation, depletion, and amortization, interest and income taxes being based on the status and elections of the trust unitholders. In addition, the royalty interest will not be burdened by field and lease operating expenses. Thus, the statement purports to show distributable income, defined as income of the Trust available for distribution to the trust unitholders before application of those additional unitholders’ additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses. Actual cash receipts may vary due to timing delays of actual cash receipts from the property purchasers and due to wellhead and pipeline volume balancing agreements or practices.

Investment in royalty interest is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. The Trust will provide a write-down to its investment in the royalty interests to the extent the total capitalized costs, less accumulated depreciation, depletion and amortization, exceed undiscounted future net revenues attributable to the proved natural gas reserves of the Underlying Properties.

ECA believes that the assumptions used provide a reasonable basis for presenting the significant effects directly attributable to this transaction.

F-16

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information — (Continued)

The unaudited pro forma financial information should be read in conjunction with the Statement of Assets and Trust Corpus and the Statement of Historical Revenues and Direct Operating Costs for Underlying PDP Properties and related notes for the period presented.


NOTE 3.	INCOME TAXES

The Trust is a Delaware statutory trust and is not required to pay federal or state income taxes. Accordingly, no provision for federal or state income taxes has been made.


NOTE 4.	PRO FORMA ADJUSTMENTS

(a) Reflects ECA’s transfer of certain natural gas floor price contracts and back-to-back swap arrangements and the conveyance of the royalty interests to the Trust in exchange for all of the net proceeds of this offering as well common and subordinated units representing a 50% beneficial interest in the trust, with all trust units valued at the initial public offering price of the common units.

(b) Until the earlier of the expiration of the subordination period (as defined in Note 1) or such time as the reimbursement amount has been paid in full, the trust will pay ECA an amount equal to 50% of the amount by which the cash receipts in respect of the royalties in any quarter exceeds the applicable incentive threshold. Such obligation includes interest on the reimbursement amount accruing at 10% per annum. ECA bears the risk that the subordination period will end before it is reimbursed in full.

(c) Historical well production and lease production expenses and marketing fee are not deducted in determining net revenue attributable to the royalty interests and in determining distributable income. Royalty interests, as defined in the conveyance, will bear a pro rata share of taxes on production and property, if any, and applicable gathering/post-production expenses relating to make the gas saleable.

(d) The Trust’s general and administrative expenses are estimated at $800,000 annually. Such expenses include trustee fees, administrative service fees and costs associated with being a public entity. Pennsylvania state franchise taxes are estimated at $150,000.

(e) Assumes that no incentive threshold was reached during the period.

F-17

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information — (Continued)


5.	SUPPLEMENTAL INFORMATION ON GAS PRODUCING ACTIVITIES

Information with respect to gas producing activities of the trust’s royalty interests in the Underlying Properties is presented in the following tables. The information was derived from reserve reports which were prepared by independent reserve engineers as of December 31, 2009, in accordance with ASU 2010-03 “Extractive Activities — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures.”

Gas Reserves

The following table summarizes the estimated quantities of the proved natural gas reserves (MMcfs) attributable to the trust’s royalty interests:


	Natural Gas
	(Mmcf)

Proved reserves:
June 30, 2009		—

Revisions of previous estimates		—
Extensions and discoveries		105,907
Sales of reserves in place		—
Purchases of reserves in place		—
Production		(757	)

December 31, 2009		105,150

Proved developed reserves:
December 31, 2009		8,125

Proved behind pipe reserves:
December 31, 2009		8,228

Proved undeveloped reserves:
December 31, 2009		88,797

F-18

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information — (Continued)

Estimated Present Value of Future Net Cash Flows

Standardized Measure of Discounted Future Net Cash Flows — Estimated discounted future net cash flows and changes therein were determined in accordance with ASC 932, “Disclosures About Oil and Gas Producing Activities.” Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. ECA believes such information is important to a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying the average prices of gas during the 12-month period ending December 31, 2009, determined using the unweighted arithmetic average of the prices in effect on the first-day-of-the-month for each month within the period relating to the trust’s royalty interest proved reserves to the period-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at period-end.

Future production costs are computed by estimating the expenditures to be incurred in producing the proved gas reserves at December 31, 2009, based on period-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are not computed as the Trust is not required to pay federal or state income taxes.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved gas reserves in accordance with the rules and regulations of the SEC.

Information with respect to the trust’s royalty interest in estimated discounted future net cash flows related to its proved gas reserves as of December 31, 2009 is as follows (in thousands):


	2009

Future cash in flows	$	419,139
Future production cost (gathering and transportation)		(56,318	)
Future income tax expense		—

Future net cash flows before discount		362,821
10% discount to present value		(179,197	)

Standardized measure of discounted future net cash flows related to proved oil and gas reserves	$	183,624

F-19

ECA MARCELLUS TRUST I

Notes to Unaudited Pro Forma Financial Information — (Continued)

The changes in the standardized measure of discounted future net cash flows relating to proved gas reserves as of December 31, 2009 is as follows (in thousands):


	2009

Standardized measure of discounted future net cash flows at beginning of period	$	—
Sales of oil and gas produced, net of production costs		(2,849	)
Net changes in prices and production costs		—
Changes in production rates and other		—
Extensions, discoveries and other additions, net of future production and development costs		186,473
Changes in estimated future development costs		—
Development costs incurred		—
Revisions of previous quantity estimates		—
Purchase of reserves in place		—
Accretion of discount		—
Net change in income taxes		—

Standardized measure of discounted future net cash flows at end of period	$	183,624

F-20

INFORMATION ABOUT ENERGY CORPORATION OF AMERICA

The trust units are not interests in or obligations of

Energy Corporation of America

ECA-1

Business of Energy Corporation of America

General

Energy Corporation of America (“ECA” or the “Company”) is a privately held energy company engaged in the exploration, development, production, gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and ECA is one of the largest natural gas operators in the Appalachian Basin. As of December 31, 2009, ECA operated approximately 5,100 wells in the Appalachian Basin and had an aggregate net leasehold position of approximately one million acres, with 85% of this acreage held by production. ECA sells gas from its own wells as well as third-party wells to local gas distribution companies, industrial end users located in the Northeast, other gas marketing entities and into the spot market for gas delivered into interstate pipelines. ECA owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities. During the fiscal year ended June 30, 2009, ECA aggregated and sold 22.5 Bcf of gas for an average of 62 MMcf of gas per day, of which 20.7 Bcf, or 57 MMcf per day, represented sales of gas produced from wells operated by ECA.

Gas And Oil Development And Production

Operations and Significant Developments

The Company’s proved developed net natural gas and oil reserves are estimated as of July 1, 2009 at 143,167 MMcf and 322 MBbls, respectively. For the fiscal year ended June 30, 2009, the Company’s net natural gas production was 9,364 MMcf and net oil production was 47 MBbls, for a total of 9,646 net MMcfe.

Development Activity

During the fiscal year ended June 30, 2009, the Company drilled 26 productive gross wells (20.9 net) and recompleted four wells. The average first month gross production rate for the four horizontal Marcellus Shale wells that the Company drilled in Greene County, Pennsylvania in fiscal year 2009 was 2,334 Mcf per day per well. The average first month gross production rate for the seven vertical Marcellus Shale wells that the Company drilled in Greene County, Pennsylvania in fiscal year 2009 was 193.4 Mcf per day per well. The average first month gross production rate for the other 15 wells that the Company drilled in fiscal year 2009 was 162.3 Mcf per day per well. The average initial increase in gross production rate for the four wells that the Company recompleted in fiscal year 2009 in Fort Bend County, Texas was 926.5 Mcf per day per well.

Competition

Given the increased activity in the Marcellus Shale formation, the Company will encounter substantial competition in acquiring properties, aggregating oil and natural gas, securing drilling equipment and personnel and operating its properties. The competitors in acquisitions,

ECA-2

development, exploration and production include major oil companies, numerous independent oil and natural gas companies, natural gas marketers, individual proprietors and others.

Regulations Affecting Operations

The Company’s operations are affected by extensive regulation pursuant to various federal, state and local laws and regulations relating to the exploration for and development, production, gathering, aggregation, transportation and storage of oil and natural gas. These regulations, among other things, can affect the rate of oil and natural gas production. The Company’s operations are subject to numerous laws and regulations governing plugging and abandonment, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution which might result from the Company’s operations. The Company believes it is in substantial compliance with applicable regulations.

Gas Aggregation and Pipelines

The Company, primarily through its wholly owned subsidiary Eastern Marketing Corporation (“Eastern Marketing”), aggregates natural gas through the purchase of production from properties in the Appalachian Basin, including the Marcellus Shale, in which the Company has an interest, the purchase of natural gas delivered through the Company’s gathering pipelines located in the Appalachian Basin, and the purchase of natural gas in the spot market. The Company sells natural gas to local natural gas distribution companies, industrial end users located in the Northeast, other natural gas marketing entities and into the spot market for natural gas delivered into interstate pipelines.

The Company owns and operates approximately 5,000 miles of gathering lines and intrastate pipelines that are used in connection with its gas aggregation activities. During the fiscal year ended June 30, 2009, ECA and its affiliates aggregated and sold 22.5 Bcf of natural gas for an average of 62 MMcf of natural gas per day, of which 20.7 Bcf, or 57 MMcf per day, represented sales of natural gas produced from wells operated by ECA. Substantially all of the production subject to the PDP Royalty Interest and PUD Royalty Interest will be gathered by ECA’s Greene County Gathering System. This system currently accesses two separate interconnects with the Texas Eastern Transmission, L.P. and Columbia Gas Transmission, L.L.C. interstate pipeline systems and includes (6) compressors (with 8,860 total horsepower) together with associated processing equipment. ECA will add additional compression and related facilities as the field is developed. ECA’s interconnect agreements with these interstate pipelines currently allow it to deliver at the interconnections between ECA’s facilities and the interstate pipelines, up to 110,000 MMBtu per day for transportation by the interstate pipelines to ECA’s customers (approximately 16,000 MMBtu per day is currently being utilized), on these two interstate pipeline systems, which is in excess of its current and expected volumes from the Underlying Properties. To the extent necessary, ECA will add additional compression and related facilities to this System at no cost to the trust, other than potential increases in gathering rates as a result of capital expenditures.

ECA-3

Regulations Affecting Marketing and Transportation

As a purchaser of natural gas, the Company depends on the transportation, gathering and storage services offered by various interstate and intrastate pipeline companies for the delivery and sale of its own natural gas supplies as well as those it processes and/or markets for others. Both the performance of transportation and storage services by interstate pipelines and the rates charged for such services are subject to the jurisdiction of the Federal Energy Regulatory Commission. In addition, the performance of transportation, gathering and storage services by intrastate pipelines and the rates charged for such services are subject to the jurisdiction of state regulatory agencies.

Oil and Gas Reserves

The following information relating to estimated reserve quantities, reserve values and discounted future net revenues is derived from, and qualified in its entirety by reference to, the more complete reserve and revenue information and assumptions included in the Company’s Supplemental Oil and Gas Disclosures in the Company’s financial statements. The Company’s estimates of proved reserve quantities of its properties have been subject to review by Ryder Scott Company, independent petroleum engineers. In December 2008, the Securities and Exchange Commission (the “SEC”) announced that it had approved revisions to modernize its oil and gas reserves reporting requirements. The following reserve information was calculated based on the SEC reserve reporting requirements in effect for the periods presented, which do not give effect to the new SEC requirements. Accordingly, the reserve information presented below is calculated based on year-end pricing information. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve information represents estimates only and should not be construed as being exact. Future reserve values are based on fiscal year-end prices except in those instances where the sale of natural gas and oil is covered by contract terms. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalations. The table below does not give effect to derivative transactions.

The following table sets forth the Company’s estimated proved and proved developed reserves and the related estimated future value, as of June 30:


	2007		2008		2009

Net proved developed:
Gas (MMcf)		170,625		174,396		143,167

Oil (MBbls)		475		379		322

Total (MMcfe)		173,474		176,672		145,099

Weighted Average Price ($/Mcf)		7.43		14.41		3.88
Future net cash flows before discount (in thousands)	$	737,309	$	1,362,849	$	370,421

Discounted future net cash flows related to proved developed oil and gas reserves (in thousands) (1)	$	261,229	$	492,670	$	153,646


(1)		Discounted using an annual discount rate of 10%.

ECA-4

The following table sets forth the Company’s estimated proved reserves and the related estimated present value by region, as of June 30, 2009:


	Natural Gas		Oil		Natural Gas		Percent of Proved			Present Value
Region	(MMcf)		(Mbbls)		Equivalent (MMcfe)		Developed Reserves			(Thousands)

Appalachian Basin	$	140,080		249		141,574		97.6	%	$	147,129
Western		3,087		73		3,525		2.4	%		6,517

Total	$	143,167		322		145,099		100.0	%	$	153,646	(1)


(1)		Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved developed reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at June 30, 2009. Prices were determined by applying period-end prices of oil and natural gas relating to the Company in accordance with the SEC’s ruling in effect as of June 30, 2009, and do not give effect to any derivative transactions. This price should not be interpreted as a prediction of future prices, nor does it reflect the value of commodity hedges in place at June 30, 2009. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization.

Producing Wells

The following table sets forth certain information relating to productive wells at June 30, 2009. Wells are classified as oil or natural gas according to their predominant production stream.


	Gross Wells						Net Wells
Region	Oil		Gas		Total		Oil		Gas		Total

Appalachian Basin		50		5,094		5,144		35.4		3,527.9		3,563.3
Western		—		24		24		0		11.3		11.3

Total		50		5,118		5,168		35.4		3,539.2		3,574.6

Acreage

The following table sets forth the developed and undeveloped gross and net acreage held at June 30, 2009:


	Developed Acreage				Undeveloped Acreage
Region	Gross		Net		Gross		Net

Appalachian Basin		836,277		766,676		189,405		163,993
Western		21,709		9,356		22,892		15,248
New Zealand		—		—		1,732,209		1,555,776

Total		857,986		776,032		1,944,506		1,735,017

ECA-5

Production

The following table sets forth certain net production data and average wellhead sales prices attributable to the Company’s properties for the years ended June 30:


	2007		2008		2009

Production data:
Oil (MBbls)		83		65		47
Natural gas (MMcf)		9,138		10,294		9,364
Average sales price (before the effect of hedging):
Oil per Bbl	$	60.10	$	92.37	$	64.98
Natural gas per Mcf	$	7.01	$	8.53	$	6.76

Drilling Activities

The Company’s natural gas and oil exploratory and developmental drilling activities are as follows for the years ended June 30. The number of wells drilled refers to the number of wells commenced at any time during the respective fiscal year. A well is considered productive if it justifies the installation of permanent equipment for the production of natural gas or oil.


	2007				2008				2009
	Gross		Net		Gross		Net		Gross		Net

Development
Productive
Appalachian		93		80.3		93		82.1		24		19.5
Western/New Zealand		2		1.8		2		1.8		—		—

Total		95		82.1		95		83.9		24		19.5
Nonproductive
Appalachian		—		—		—		—		—		—
Western/New Zealand		—		—		—		—		—		—

Total		—		—		—		—		—		—
Exploratory:
Productive
Appalachian		5		4.5		2		1.8		2		1.4
Western/New Zealand		—		—		—		—		—		—

Total		5		4.5		2		1.8		2		1.4
Nonproductive
Appalachian		—		—		—		—		—		—
Western/New Zealand		1		1		1		0.7		—		—

Total		101		87.6		98		86.4		26		20.9

ECA-6

Selected Consolidated Financial Data of Energy Corporation Of America

The following selected consolidated statements of operations data of Energy Corporation of America and its subsidiaries for each of the three years in the period ended June 30, 2009 and the selected consolidated balance sheet data for Energy Corporation of America and its subsidiaries as of June 30, 2008 and 2009 are derived from the audited consolidated financial statements of Energy Corporation of America and its subsidiaries included elsewhere in this prospectus. The following selected consolidated statement of operations data for the six months ended December 31, 2008 and 2009 and the selected consolidated balance sheet data as of December 31, 2008 and 2009 are derived from the unaudited consolidated financial statements of Energy Corporation of America and its subsidiaries included elsewhere in this prospectus. The selected consolidated balance sheet data presented as of June 30, 2008 has been derived from the audited consolidated financial statements of Energy Corporation of America and its subsidiaries, which are not included in this prospectus. The information in the table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Energy Corporation of America” beginning on page ECA-8 of this prospectus and the consolidated financial statements of Energy Corporation of America and its subsidiaries, related notes and other financial information included elsewhere in this prospectus.


	Year Ended June 30,									Six Months Ended December 31,
	2007			2008			2009			2008			2009
										(Unaudited)
	(In thousands, except per share data)

Revenues:
Oil and gas sales	$	84,429		$	96,514		$	92,262		$	45,703		$	44,012
Gas aggregation and pipeline sales		120,549			142,825			116,730			75,655			37,240
Well operations and service revenues		6,976			7,732			7,228			3,752			3,788

		211,954			247,071			216,220			125,110			85,040

Costs and expenses:
Field operating expenses		17,700			18,234			18,772			9,754			9,085
Gas aggregation and pipeline cost of sales		110,226			131,051			104,685			68,678			31,867
General and administrative		17,742			17,933			18,858			9,417			8,678
Taxes, other than income		4,519			5,406			4,629			3,022			395
Depletion and depreciation of oil and gas properties		18,115			20,937			23,445			11,496			17,179
Depreciation of pipelines, other property and equipment		4,961			5,852			6,119			2,999			3,148
Exploration and impairment		8,487			3,033			18,476			9,878			10,460
(Gain) on sale of assets		(10,454	)		(7,287	)		(9,114	)		(5,612	)		(7,761	)

		171,296			195,159			185,870			109,632			73,051

Income from operations		40,658			51,912			30,350			15,478			11,989

ECA-7


	Year Ended June 30,									Six Months Ended December 31,
	2007			2008			2009			2008			2009
										(Unaudited)
	(In thousands, except per share data)

Other (income) and expense:
Interest expense		8,245			10,688			9,986			5,366			4,796
Interest income (expense) and other		8,547			21,884			(18,722	)		(17,317	)		3,656

		16,792			32,572			(8,736	)		(11,951	)		8,452

Income from operations before income taxes		23,866			19,340			39,086			27,429			3,537
Income tax expense		4,815			7,855			17,355			12,513			1,868

Net income	$	19,051		$	11,485		$	21,731		$	14,916		$	1,669

Earnings per common share, basic and diluted:	$	33.66		$	19.93		$	36.98		$	25.39		$	2.85

Balance sheet data (at end of period):
Property, plant and equipment	$	347,617		$	451,742		$	479,722		$	455,876		$	478,768
Total assets		413,321			557,980			543,719			538,501			534,025
Working capital deficiency		(41,155	)		(78,179	)		(23,997	)		(10,165	)		(17,515	)
Long term debt excluding current maturities		135,166			197,125			218,134			213,490			237,779
Stockholders’ equity		69,891			24,666			100,935			99,645			89,859

ECA-8

Management’s Discussion and Analysis of Financial Condition
and Results of Operations of Energy Corporation of America

The following discussion should be read in conjunction with the consolidated financial statements and the related notes thereto of Energy Corporation of America and its subsidiaries appearing elsewhere in this prospectus.

Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995

This discussion and analysis of financial condition and results of operations, and other sections of this prospectus, contain forward-looking statements that are based on management’s beliefs, assumptions, current expectations, estimates, intentions and projections about the oil and natural gas industry, the economy and about the Company itself. Words such as “anticipates,” “believes,” “estimates,” “expects,” “forecasts,” “intends,” “is likely,” “plans,” “predicts,” “projects,” variations of such words and similar expressions are intended to identify such forward-looking statements under the Private Securities Litigation Reform Act of 1995. The Company cautions that these statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict with regard to timing, extent, likelihood and degree of occurrence. Therefore, actual results and outcomes may materially differ from what may be expressed or forecasted in such forward-looking statements. Furthermore, the Company undertakes no obligation to update, amend or clarify forward-looking statements, whether as a result of new information, future events or otherwise.

Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to, weather conditions, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources, the timing and extent of the Company’s success in discovering, acquiring, developing and producing oil and natural gas reserves, risks incident to the drilling and operation of oil and natural gas wells, future production and development costs, foreign currency exchange rates, the effect of existing and future laws, governmental regulations and the political and economic climate of the United States and New Zealand, the effect of hedging activities, and conditions in the capital markets.

The following should be read in conjunction with the Company’s selected consolidated financial statements and the related notes (including the segment information) beginning on page ECA-23 of this prospectus.

Critical Accounting Policies And Estimates

The discussion of financial condition and results of operation are based upon the information reported in the consolidated financial statements. The preparation of these financial statements requires the Company to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities at the date of the financial statements. Decisions are based on historical experience and various other sources that are believed to be reasonable under the circumstances. Actual results may differ from the estimates due to changing business conditions or unexpected circumstances. The Company believes the following policies are critical to understanding our business and results of operations. For additional information on significant accounting policies, see Notes to Consolidated Financial Statements, particularly Note 2.

Revenue Recognition — The Company is engaged in the exploration, development, acquisition, production and aggregation of natural gas and crude oil. The revenue recognition policy is significant because it is a key component of the results of operations and forward looking statements contained in “Liquidity and Capital Resources” below. Revenue is derived

ECA-9

primarily from the sale of produced natural gas and crude oil. Revenue is recorded in the month production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. Monthly, the Company makes estimates of the amount of production delivered to the purchaser and the price to be received. The Company uses its knowledge of properties, historical performance, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between the estimates and the actual amounts received, which historically have not been significant, are recorded in the month revenue is distributed.

Derivative Instruments — The estimated fair values of all derivative instruments are recorded on the consolidated balance sheet. All of the derivative instruments are entered into to mitigate risks related to the prices to be received for future natural gas and oil production. Derivative instruments are not used for trading purposes. Although derivatives are reported on the balance sheet at fair value, to the extent that instruments qualify for hedge accounting treatment, changes in fair value are recorded, net of taxes, directly to stockholders’ equity as a component of other comprehensive income until the hedged oil or natural gas quantities are produced. To the extent changes in the fair values of derivatives relate to instruments not qualifying for hedge accounting treatment, such changes are recorded in operations in the period they occur. In determining the amounts to be recorded, the Company is required to estimate the fair values of derivatives. The estimates are based upon various factors that include contract volumes and prices, contract settlement dates, quoted closing prices on the NYMEX or over-the-counter, volatility and the time value of options. The estimated future prices are compared to the prices fixed by the derivatives agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and regional price differences. Periodically the valuations are validated using independent third party quotations.

Reserve Estimates — The Company’s estimate of natural gas and oil reserves are projections based on geologic and engineering data. There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows depend upon a number of variable factors and assumptions, such as expected future production rates, natural gas and oil prices, operating costs, severance taxes, and development costs, all of which may vary considerably from actual results. Expected cash flows are reduced to present value using a discount rate of 10%, as required by accounting standards. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of proved producing oil and natural gas properties. Reserve estimates are calculated based on the SEC reserve reporting requirements in effect for the periods presented, which do not give effect to the new SEC reserve reporting requirements. Accordingly, reserve estimates are based on year-end pricing information. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties and their rates of depletion. Changes in these calculations, caused by changes in reserve quantities or net cash flows are recorded on a prospective basis. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates and such variances may be material.

ECA-10

Valuation Of Long-Lived and Intangible Assets — Property and equipment are recorded at cost. The carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Different pricing assumptions or discount rates would result in a different calculated impairment.

Income Taxes — The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Federal and state income tax returns are generally not filed before the consolidated financial statements are prepared, therefore an estimate of the tax basis of assets and liabilities is determined at the end of each period as well as the effects of tax rate changes, tax credits and net operating loss carryforwards. Adjustments related to differences between the estimates and actual amounts are recorded in the period the income tax returns are filed.

Comparison of Results of Operations for the Years Ended June 30, 2009 and 2008

The Company realized net income of $21.7 million for the year ended June 30, 2009 compared to net income of $11.5 million for the year ended June 30, 2008. The increase of $10.2 million was primarily attributable to the net effect of a $30.9 million decrease in revenue, a $9.3 million decrease in costs and expenses, a $0.7 million decrease in interest expense, a $40.6 million increase in interest and other income and a $9.5 million increase in income tax expense.

Production, aggregation and pipeline volumes, revenue and average sales prices for the years ended June 30 and their related variances are as follows:


	Years Ended
	June 30,				Variance
	2008		2009		Amount			Percent

Natural gas
Production (MMcf)		10,294		9,364		(930	)		(9.0	)%
Average sales price received ($/Mcf)	$	8.53	$	6.76	$	(1.77	)		(20.7	)%

Sales (in thousands)	$	87,816	$	63,339	$	(24,477	)		(27.9	)%
Oil
Production (MBbl)		65		47		(18	)		(27.7	)%
Average sales price received ($/Bbl)	$	92.37	$	64.98	$	(27.39	)		(29.7	)%

Sales (in thousands)	$	6,004	$	3,054	$	(2,950	)		(49.1	)%
Hedging		2,417		25,602		23,185			959.2	%
Other		277		267		(10	)		(3.6	)%

Total oil and gas sales (in thousands)	$	96,514	$	92,262	$	(4,252	)		(4.4	)%

ECA-11


	Years Ended
	June 30,				Variance
	2008		2009		Amount			Percent

Aggregation revenue
Volume (Million MMBtu)		12,607		13,165		558			4.4	%
Average sales price received ($/MMBtu)	$	8.73	$	6.99	$	(1.74	)		(19.9	)%

Sales (in thousands)	$	110,029	$	92,003	$	(18,026	)		(16.4	)%
Pipeline revenue
Volume (Million MMBtu)		12,863		11,906		(957	)		(7.4	)%
Average sales price received ($/MMBtu)	$	2.55	$	2.08	$	(0.47	)		(18.5	)%

Sales (in thousands)	$	32,796	$	24,727	$	(8,069	)		(24.6	)%

Total aggregation and pipeline sales (in thousands)	$	142,825	$	116,730	$	(26,095	)		(18.3	)%

Aggregation gas cost
Volume (Million MMBtu)		12,607		13,165		558			4.4	%
Average price paid ($/MMBtu)	$	8.49	$	6.74	$	(1.75	)		(20.6	)%

Cost (in thousands)	$	107,058	$	88,767	$	(18,291	)		(17.1	)%
Pipeline gas cost
Volume (Million MMBtu)		3,407		2,828		(579	)		(17.0	)%
Average price paid ($/MMBtu)	$	7.04	$	5.63	$	(1.41	)		(20.0	)%

Cost (in thousands)	$	23,993	$	15,918	$	(8,075	)		(33.7	)%

Total aggregation and pipeline sales (in thousands)	$	131,051	$	104,685	$	(26,366	)		(20.1	)%

REVENUES. Total revenues decreased $30.9 million or 12.5% between the years. The decrease was due to a 4.4% decrease in oil and natural gas sales, an 18.3% decrease in natural gas aggregation and pipeline sales, and a 6.5% decrease in well operations and service revenues.

Revenues from oil and natural gas sales decreased $4.2 million from $96.5 million for the year ended June 30, 2008 to $92.3 million for the year ended June 30, 2009. Natural gas sales decreased $24.5 million and oil sales decreased $3.0 million between such periods. The decreases are a result of a decrease in both the average sales price received and production. The price decline corresponds with the change in related indexes. The decrease in production is primarily the result of the shut in of certain properties due to low pricing conditions in Montana and equipment failure on certain producing properties in Texas. The decrease in production revenue was largely offset by an increase in recognized gains on related derivative instrument hedging transactions on natural gas and oil production which totaled $25.6 million for the year ended June 30, 2009 as compared to a gain of $2.4 million for the year ended June 30, 2008. The average price per Mcfe, after hedging, was $9.56 and $9.03 for the years ended June 30, 2009 and 2008, respectively.

Revenues from natural gas aggregation and pipeline sales decreased $26.1 million from $142.8 million during the period ended June 30, 2008 to $116.7 million for the period ended June 30, 2009. Gas aggregation revenue decreased $18.0 million while pipeline revenue, which has a sales and a transportation component, decreased $8.1 million. The decrease in natural gas aggregation and pipeline sales is attributable to the decline in average sales price received and a decrease in pipeline volumes. The price decrease corresponds with the decline in the related index price of natural gas.

ECA-12

COSTS AND EXPENSES. The Company’s costs and expenses decreased $9.3 million or 4.8% between the years. The net decrease was due to a 3.0% increase in field and lease operating expenses, a 20.1% decrease in natural gas aggregation and pipeline costs, a 5.2% increase in general and administrative expenses, a 14.4% decrease in taxes other than income, a 12.0% increase in oil and natural gas related depletion, a 4.6% increase in depreciation and amortization expenses of pipelines, property and equipment, a 509.1% increase in exploration and impairment costs, and an increase in the gain on sale of property of 25.1%.

Field and lease operating expenses increased $0.5 million. The increase is primarily related to an increase in utilities and compressor rentals related to upgraded and new facilities and natural gas transmission costs for recently drilled properties.

Gas aggregation and pipeline costs decreased $26.4 million. Gas aggregation cost decreased $18.3 million while pipeline cost decreased by $8.1 million. The decrease in natural gas aggregation cost is attributable to the decline in average purchase price partially offset by an increase in volumes aggregated during the period. The decrease in pipeline costs is a result of a decrease in price and volumes. The decline in price corresponds with the decrease in related indexes.

General and administrative expenses increased $0.9 million primarily as a result of an increase in payroll and associated tax costs.

Taxes other than income decreased $0.8 million primarily as a result of decreased wellhead oil and natural gas sales.

Depletion, depreciation and amortization of oil and natural gas properties expense increased $2.5 million due to an increase in depletion rates recognized by the Company.

Exploration and impairment costs increased $15.4 million. The increase is a result of higher expenses primarily related to dry hole costs in New Zealand and various other geological and geophysical costs.

Gain on sale of property increased $1.8 million primarily as a result of an increase in incentive distributions related to a certain term royalty conveyance.

INTEREST EXPENSE. Interest expense decreased $0.7 million due to lower interest rates, offset partially by an increase in outstanding borrowings.

INTEREST INCOME AND OTHER. Other non-operating income increased by $40.6 million primarily as a result of an increase in derivative mark-to-market adjustments and settlement gains.

INCOME TAX. Income tax expense increased $9.5 million primarily as a result of the increase in income before tax and due to the expiration of certain deferred tax carryovers that could no longer be utilized.

Comparison of Results of Operations for the Years Ended June 30, 2008 and 2007

The Company realized net income of $11.5 million for the year ended June 30, 2008 compared to net income of $19.1 million for the year ended June 30, 2007. The decrease of $7.6 million was primarily attributable to the net effect of a $35.1 million increase in revenue, a

ECA-13

$23.9 million increase in costs and expenses, a $2.4 million increase in interest expense, a $13.3 million increase in other expenses and a $3.0 million increase in income tax expense.

Production, aggregation and pipeline volumes, revenue and average sales prices for the years ended June 30 and their related variances are as follows:


	Years Ended
	June 30,				Variance
	2007		2008		Amount			Percent

Natural gas
Production (MMcf)		9,138		10,294		1,156			12.7	%
Average sales price received ($/Mcf)	$	7.01	$	8.53	$	1.52			21.7	%

Sales (in thousands)	$	64,024	$	87,816	$	23,792			37.2	%
Oil
Production (MBbl)		83		65		(18	)		(21.7	)%
Average sales price received ($/Bbl)	$	60.10	$	92.37	$	32.27			53.7	%

Sales (in thousands)	$	4,988	$	6,004	$	1,016			20.4	%
Hedging		15,201		2,417		(12,784	)		(84.1	)%
Other		216		277		61			28.2	%

Total oil and gas sales (in thousands)	$	84,429	$	96,514	$	12,085			14.3	%

Aggregation revenue
Volume (Million MMBtu)		12,724		12,607		(117	)		(0.9	)%
Average sales price received ($/MMBtu)	$	7.27	$	8.73	$	1.46			20.1	%

Sales (in thousands)	$	92,500	$	110,029	$	17,529			19.0	%
Pipeline revenue
Volume (Million MMBtu)		11,800		12,863		1,063			9.0	%
Average sales price received ($/MMBtu)	$	2.38	$	2.55	$	0.17			7.1	%

Sales (in thousands)	$	28,049	$	32,796	$	4,747			16.9	%

Total aggregation and pipeline sales (in thousands)	$	120,549	$	142,825	$	22,276			18.5	%

Aggregation gas cost
Volume (Million MMBtu)		12,724		12,607		(117	)		(0.9	)%
Average price paid ($/MMBtu)	$	7.20	$	8.49	$	1.29			17.9	%

Cost (in thousands)	$	91,669	$	107,058	$	15,389			16.8	%
Pipeline gas cost
Volume (Million MMBtu)		4,422		3,407		(1,015	)		(23.0	)%
Average price paid ($/MMBtu)	$	4.20	$	7.04	$	2.84			67.6	%

Cost (in thousands)	$	18,557	$	23,993	$	5,436			29.3	%

Total aggregation and pipeline sales (in thousands)	$	110,226	$	131,051	$	20,825			18.9	%

REVENUES. Total revenues increased $35.1 million or 16.6% between the years. The increase was due to a 14.3% increase in oil and natural gas sales, an 18.5% increase in natural gas aggregation and pipeline sales, and a 10.8% increase in well operations and service revenues.

Revenues from oil and natural gas sales increased $12.1 million from $84.4 million for the year ended June 30, 2007 to $96.5 million for the year ended June 30, 2008. Natural gas sales increased $23.8 million and oil sales $1.0 million. The increase is a result of an increase in both average sales price received and production. The price increase corresponds with the change in related indexes. The increase in production is primarily the result of new wells drilled and the reduction of shut-in volumes compared to the prior period. The recognized gains on related derivative instrument hedging transactions on natural gas and oil production decreased by

ECA-14

$12.8 million from $15.2 million for the year ended June 30, 2007 as compared to $2.4 million for the year ended June 30, 2008. The average price per Mcfe, after hedging, was $9.03 and $8.76 for the years ended June 30, 2008 and 2007, respectively.

Revenues from natural gas aggregation and pipeline sales increased $22.3 million from $120.6 million during the period ended June 30, 2007 to $142.8 million for the period ended June 30, 2008. Gas aggregation revenue increased $17.5 million while pipeline revenue, which has a sales and a transportation component, increased $4.8 million. The increase in natural gas aggregation and pipeline sales is attributable to the increase in average sales price received and an increase in pipeline volumes. The price increase corresponds with the increase in the related index price of natural gas.

COSTS AND EXPENSES. The Company’s costs and expenses increased $23.9 million or 13.9% between the years. The net increase was due to a 3.0% increase in field and lease operating expenses, an 18.9% increase in natural gas aggregation and pipeline costs, a 1.1% increase in general and administrative expenses, a 19.6% increase in taxes other than income, a 15.6% increase in oil and natural gas related depletion, an 18.0% increase in depreciation and amortization expenses of pipelines, property and equipment, a 64.3% decrease in exploration and impairment costs, and a decrease in the gain on sale of property of 30.3%.

Field and lease operating expenses increased $0.5 million. The increase is primarily related to an increase in payroll and associated tax costs and land delay rentals for newly acquired acreage.

Gas aggregation and pipeline costs increased $20.8 million. Gas aggregation cost increased $15.4 million while pipeline cost increased by $5.4 million. The increase in natural gas aggregation cost is attributable to the increase in average purchase price during the period. The increase in pipeline costs is a result of the increase in price and volumes. The increase in price corresponds with the increase in related indexes.

Taxes other than income increased $0.9 million primarily as a result of increased wellhead oil and natural gas sales.

Depletion, depreciation and amortization of oil and natural gas properties expense increased $2.8 million as a result of increased production and a higher depletion rate.

Depletion, depreciation and amortization of pipelines, property and equipment expense increased $0.9 million due to a change in the estimated useful life for certain pipeline assets and the acquisition of other fixed assets.

Exploration and impairment costs decreased $5.5 million. The decrease is a result of a reduction in impairment expense and various other geological and geophysical costs.

Gain on sale of property decreased $3.2 million primarily due to the sale of certain properties during the year ended June 30, 2007.

INTEREST EXPENSE. Interest expense increased $2.4 million primarily due to an increase in outstanding borrowings for the year ended June 30, 2008.

INTEREST INCOME AND OTHER. Other non-operating expense increased by $13.3 million primarily as a result of an increase in derivative mark-to-market adjustments and settlement losses for the year ended June 30, 2008.

ECA-15

INCOME TAX. Income tax expense increased $3.0 million primarily as a result of recording a tax benefit during the year ended June 30, 2007 for expiring tax contingency items.

Comparison of Results of Operations for the Six Months Ended December 31, 2009 and 2008

The Company realized net income of $1.7 million for the six months ended December 31, 2009 compared to net income of $14.9 million for the six months ended December 31, 2008. The decrease of $13.2 million was primarily attributable to the net effect of a $40.1 million decrease in revenue, a $36.6 million decrease in costs and expenses, a $0.6 decrease in interest expense, a $21.0 million decrease in interest and other income and a $10.6 million decrease in income tax expense.

Production, aggregation and pipeline volumes, revenue and average sales prices for the six months ended December 31 and their related variances are as follows:


	Six Months Ended
	December 31,				Variance
	2008		2009		Amount			Percent

Natural gas
Production (MMcf)		4,709		5,314		605			12.8	%
Average sales price received ($/Mcf)	$	9.14	$	3.78	$	(5.36	)		(58.6	)%

ENERGY CORP OF AMERICA S-1/A