As filed with the Securities and Exchange Commission on April 1, 2010

Registration No. 333-          

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Approximate date of commencement of proposed sale to the public:

As soon as practicable after this Registration Statement becomes effective.

 

 

Copies to:

 

 

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):

 

 

 

CALCULATION OF REGISTRATION FEE

 

 

 

 

 

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.

 

 

Subject to Completion dated April 1, 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 certain royalty interests and natural gas hedging contracts to the trust in exchange for a distribution from 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 intends to apply to have the common units approved for listing 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.

 

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 16 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.

 

 

 

 

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.

 

Joint Bookrunning Managers

 

 

           , 2010

 

TABLE OF CONTENTS

 

 

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

		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

		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.

	•	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 hedging contracts.
	•	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 which is nonrecourse to ECA.
	•	ECA will grant to the trust a lien, which is nonrecourse to ECA, 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.

	•	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 hedging contracts to be 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 50% of estimated production through March 31, 2014. ECA will transfer to the trust hedging contracts covering approximately 50% of the expected production volumes attributable to the trust from April 1, 2010 through March 31, 2014. These hedging contracts will consist of swap contracts and floor price hedging contracts. The swap contracts will relate to approximately 7,500 MMBtu per day at an average price of $6.78 per MMBtu for the period from April 1, 2010 through June 2012. The floor price of any floor price hedging contract 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 hedge 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.

	•	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.

		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.

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 will 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 for general corporate purposes, including for the drilling of PUD Wells.
Proposed NYSE symbol		“ECT”
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.”

 

Drilling and completion of the development wells on the underlying PUD 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 development wells on the underlying PUD 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:

 

 

 

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:

 

 

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:

 

 

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 materially increase the post-production costs 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 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 natural gas hedging contracts that will be transferred to the trust at closing.

 

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.

 

 

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 hedging contracts for the benefit of 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 hedge contracts.

 

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:

 

 

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 development 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. 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 legislation 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.

 

Two companion bills have been introduced in the U.S. Congress, known as the “Fracturing Responsibility and Awareness of Chemicals Act” (“FRAC Act”), that would repeal an exemption in the federal Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids near drinking water sources. 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 FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens involving permitting, construction standards for wells, monitoring, recordkeeping and closure of wells. The FRAC Act 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. Recently, 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. 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. Specifically, the Pennsylvania Department of Environmental Protection has adopted a new permitting policy concerning discharges to surface waters 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 FRAC Act 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, while performance of the EPA study is not imminent, 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, it would reduce the trust’s cash available for distribution to you.

 

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.

 

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.

 

This prospectus contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and the Private Securities Litigation Reform Act of 1995 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:

 

 

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.

 

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. If the proceeds decrease due to a lower initial public offering price, the trust will decrease the amount of proceeds paid to ECA’s subsidiary.

 

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 will 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 and for general corporate purposes, including for the drilling of the PUD Wells. Please read “Certain Transactions.”

 

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:

 

 

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 6,000 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.

 

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.

 

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.

 

 

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 December 31, 2009. 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.

 

 

 

 

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 December 31, 2009. 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.

 

 

 

 

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 March 24, 2010, the closing price of each Depositary Unit as reported by the New York Stock Exchange was $23.26. 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 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          , 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 obligations. ECA will grant to the trust the first perfected Drilling Support Lien on ECA’s retained interest in the AMI in order to secure the estimated amount of the drilling costs for the trust’s interests in the PUD Wells. The amount obtained by the trust pursuant to the Drilling Support Lien may not exceed $91 million. As ECA drills individual PUD Wells, the amount of the Drilling Support Lien will be reduced proportionately based on the number of PUD Wells drilled. This Drilling Support Lien is nonrecourse to ECA.

 

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 in the Marcellus Shale formation, 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 drilled all of the PUD Wells, the trustee will be required to release the Drilling Support Lien. 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.

 

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:

 

 

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.

 

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. 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 securing the hedging 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 is transferring 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 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.

 

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.

 

 

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, 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.

 

 

 

 

 

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 hedging contracts will be transferred to the trust by ECA, and ECA will be entitled to recoup the costs of establishing the hedging 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 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 to establish 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 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. 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.

 

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 Business and Operations set forth in “Information about Energy Corporation of America.”

 

 

 

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.

 

 

 

 

DISCUSSION AND ANALYSIS OF HISTORICAL RESULTS FROM THE PRODUCING WELLS

 

The Producing Wells for the six months ended December 31, 2009 consisted of four horizontal wells producing from the Marcellus Shale formation in Greene County, Pennsylvania. One well began producing in each of the months of July, August, September and October 2009. At the end of the period, all four wells were completed and producing an average of more than 5,600 Mcf per day. Total volumes produced during the period from the properties were in excess of 800,000 Mcf. 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. The average gross sales price received for gas produced was $4.31 per Mcf, before deduction of any post-production costs or operating expenses. Post-production costs, which consist of gathering and marketing fees, averaged $0.70 per Mcf. 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.

 

 

 

 

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.

 

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.

 

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:

 

 

 

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. 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, 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, the U.S. Congress has introduced a bill 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 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. Recently, 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. While performance of the EPA study is not imminent, the results of such a study, once completed, could further spur action towards federal legislation and regulation of hydraulic fracturing activities. 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.

 

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.

 

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.

 

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:

 

 

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

 

 

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:

 

 

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

 

 

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

 

 

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 contracts 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. These hedging contracts will consist of swap contracts and floor price hedging contracts. The swap contracts will relate to approximately 7,500 MMBtu per day at an average price of $6.78 per MMBtu for the period commencing as of April 1, 2010 through June 30, 2012. The floor price of any floor price hedging contract will be $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.