Table of Contents
As
filed with the Securities and Exchange Commission on March 25, 2011
Registration No. 333-172797
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 1
to
to
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
UNDER
THE SECURITIES ACT OF 1933
ECA Marcellus Trust I
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Number)
27-6522024
(I.R.S. Employer Identification No.)
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
(Address, including zip code, and telephone number,
including area code, of agent of service)
(State or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Number)
27-6522024
(I.R.S. Employer Identification No.)
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
(Address, including zip code, and telephone number,
including area code, of agent of service)
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Approximate date of commencement of proposed sale to the public:
As soon as practicable after this Registration Statement becomes effective.
Copies to:
David P. Oelman Vinson & Elkins L.L.P. First City Tower 1001 Fannin Street, Suite 2500 Houston, Texas 77002-6760 (713) 758-2222 |
Thomas W. Adkins Bracewell & Giuliani LLP 111 Congress Avenue Suite 2300 Austin, Texas 78701-4061 (512) 472-7800 |
Joshua Davidson Baker Botts L.L.P. 910 Louisiana St. Houston, Texas 77002-4995 (713) 229-1234 |
If any of the securities being registered on this Form are to be offered on a delayed or
continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.
o
If this Form is filed to register additional securities for an offering pursuant to Rule
462(b) under the Securities Act, check the following box and list the Securities Act registration
statement number of the earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities
Act, check the following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. o
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities
Act, check the following box and list the Securities Act registration statement number of the
earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
CALCULATION OF REGISTRATION FEE
Proposed Maximum | Proposed Maximum | Amount of | ||||||||||||
Amount to be | Offering Price Per | Aggregate Offering | Registration | |||||||||||
Title of Each Class of Securities to be Registered | Registered(1) | Unit | Price(1)(2) | Fee(3) | ||||||||||
Common Units |
3,001,733 | $30.04 | $90,172,060 | $10,469 | ||||||||||
(1) | Calculated in accordance with Rule 457(c) based on average high and low prices of a Common Unit as reported on the New York Stock Exchange on March 18, 2011. | |
(2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o). | |
(3) | On March 14, 2011, in connection with the initial filing of this registration statement, the Trust paid an initial filing fee of $11,902. | |
The Registrant hereby amends this Registration Statement on such date or dates as may be
necessary to delay its effective date until the Registrant 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.
Table of Contents
The information in this preliminary prospectus is not complete and may be changed. These
securities may not be sold until the registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an offer to sell these securities, and
we are not soliciting an offer to buy these securities, in any jurisdiction where the offer or sale
is not permitted. |
SUBJECT
TO COMPLETION DATED MARCH 25, 2011
PRELIMINARY PROSPECTUS
2,525,000
Common Units
Representing Beneficial Interests
ECA Marcellus Trust I
All of the shares of common units offered
by this prospectus are being sold by Energy Corporation of America (ECA). ECA Marcellus Trust I will not receive any of the proceeds from this offering.
The trusts common units are listed on the New York Stock Exchange under the symbol ECT. On
March 24, 2011 the last reported sales price of the trusts common units on the New York Stock
Exchange was $31.83 per common unit.
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.
The Trust. The trust owns term and perpetual royalty interests in natural gas properties owned
by ECA in the Marcellus Shale formation in Greene County,
Pennsylvania. These royalty interests entitle the trust to receive 90% of the proceeds attributable
to ECAs interest in the sale of production from 14 horizontal Marcellus Shale natural gas wells
located in Greene County, Pennsylvania and 50% of the proceeds attributable to ECAs interest in
the sale of production from 52 horizontal Marcellus Shale natural gas development wells that have
been or will be drilled on drill sites included within approximately 9,300 acres held by ECA, of
which it owns substantially all of the working interests, in Greene County, Pennsylvania. Of these
52 horizontal Marcellus Shale natural gas development wells, 26.83 (calculated as provided in the
Development Agreement) have been drilled as of February 28, 2011. The trust is treated as a
partnership for federal income tax purposes.
The Trust Unitholders. As a trust unitholder, you are entitled to receive quarterly
distributions of cash from the proceeds that the trust receives from ECAs sale of natural gas
subject to the royalty interests held by the trust.
ECAs Right to Incentive Distributions. ECA is entitled to receive incentive distributions
equal to 50% of the amount, if any, by which the cash available for distribution on all of the
trust units in any quarter exceeds certain target distribution levels. ECA is entitled to
reimbursement for approximately $5 million plus interest at 10% per annum in expenses incurred in
connection with establishing floor price contracts transferred to the trust from the remaining 50%
of cash available for distribution in excess of these thresholds. Please see Target distributions
and subordination and incentive thresholds.
Investing in the common units involves a high degree of risk.
Please read Risk Factors beginning on page 11 of this prospectus.
Neither the Securities and Exchange Commission nor any state securities commission has approved or
disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any
representation to the contrary is a criminal offense.
Per Common Unit | Total | |||||||
Public offering price |
$ | $ | ||||||
Underwriting discounts and commissions (1) |
$ | $ | ||||||
Proceeds to ECA (before expenses) |
$ | $ |
The underwriters may also
purchase up to an additional 360,723 common units from ECA 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. In
connection with the closing of this
offering, 116,010 common units are being conveyed by ECA to certain eligible employees. Please read Underwriting
Employee Incentive Units
Sole
Book-Running Manager
Citi
Co-Managers |
Oppenheimer & Co. | RBC Capital Markets |
, 2011
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F-1 | ||||
A-1 |
Important Notice About Information in This Prospectus
You should rely only on the information contained in this prospectus or in any free writing
prospectus we may authorize to be delivered to you. Until , 2011 (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 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 trusts business, financial condition, results of
operations and prospects may have changed since such dates.
Table of Contents
SUMMARY
This summary provides a brief overview of information contained elsewhere in this prospectus.
To understand this offering fully, you should read the entire prospectus carefully, including the
risk factors included or incorporated by reference herein and the financial statements and notes to
those statements. Definitions for terms relating to the natural gas business can be found in
Glossary of certain oil and natural gas terms and terms related to the trust. Ryder Scott
Company, L.P., an independent engineering firm, provided the estimates of proved natural gas
reserves as of December 31, 2010 included in this prospectus. These estimates are contained in a
summary prepared by Ryder Scott of its reserve report as of December 31, 2010 for the royalty
interests held by the trust, which royalty interests are referred to
herein as the Royalties. This summary is located at the back of this prospectus as Annex A and is referred to
in this prospectus as the reserve report. References to Energy Corporation of America or ECA
in this prospectus are to Energy Corporation of America and its
subsidiaries.
Unless otherwise indicated, all information in this prospectus
assumes no exercise of the underwriters over-allotment option.
ECA MARCELLUS TRUST I
ECA Marcellus Trust I is a statutory trust formed in March 2010 under the Delaware Statutory
Trust Act, pursuant to a Trust Agreement (the Trust Agreement) among Energy Corporation of
America, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the Trustee),
and Corporation Trust Company, as Delaware Trustee (the Delaware Trustee). The Trust owns
royalty interests in 14 producing horizontal natural gas wells producing from the Marcellus Shale
formation and located in Greene County, Pennsylvania (Producing Wells), and 52 horizontal natural
gas development wells drilled or to be drilled to the Marcellus Shale formation (the PUD Wells)
within the Area of Mutual Interest, or AMI, in which ECA presently holds approximately 9,300
acres, of which it owns substantially all of the working interests, in Greene County, Pennsylvania.
As of February 28, 2011, ECA had drilled eight PUD Wells which
were online and producing and an
additional thirteen PUD Wells which were undergoing or awaiting completion (which is the
equivalent of 26.83 wells, calculated as provided in the Development Agreement). The Area of
Mutual Interest consists of the Marcellus Shale formation in approximately 121 square miles. At the closing of
the initial public offering of the trust units, ECA granted the trust a lien on ECAs interest in
the Marcellus Shale formation in the AMI (exclusive of wells which were producing at that time) in
order to secure its drilling obligation to the trust. ECA is obligated to drill the remaining PUD
Wells from drill sites on approximately 9,300 leased acres in the AMI. Until ECA has satisfied its
drilling obligation, it will not be permitted to drill and complete any well in the Marcellus Shale
formation on lease acreage included within the AMI for its own account. The royalty interests were
conveyed from ECAs working interest in the Producing Wells and the PUD Wells limited to the
Marcellus Shale formation (the Underlying Properties). The royalty interest in the Producing
Wells (the PDP Royalty Interest) entitles the Trust to receive 90% of the proceeds (exclusive of
any production or development costs but after deducting post-production costs and any applicable
taxes) from the sale of production of natural gas attributable to ECAs interest in the Producing
Wells. The royalty interest in the PUD Wells (the PUD Royalty Interest and collectively, with the
PDP Royalty Interest, the Royalties) entitles the Trust to receive 50% of the proceeds (exclusive
of any production or development costs but after deducting post-production costs and any applicable
taxes) from the sale of production of natural gas attributable to ECAs interest in the PUD Wells.
Approximately 50% of the estimated natural gas production attributable to the Trusts royalty
interests has been hedged with a combination of floors and swaps through March 31, 2014. ECA is
entitled to recoup its costs of establishing the floor price contracts only if and to the extent
cash available for distribution by the Trust exceeds certain levels. Please see Target
distributions and subordination and incentive thresholds.
ECA is obligated to drill all 52 of the PUD Wells by March 31, 2013. However, in the event of
delays, ECA will have until March 31, 2014 to fulfill its
drilling obligation.
ECA has granted the trust a lien on ECAs interest in the Marcellus Shale Formation in the AMI
(except the Producing Wells and any other wells which were already producing on the grant date) in
order to secure the estimated amount of the drilling costs for the trusts interests in the PUD
Wells (the Drilling Support Lien). As of the grant date, the amount obtained by the trust pursuant to the Drilling
Support Lien could not exceed $91 million. As ECA fulfills its drilling obligation over time, the
total dollar amount that may be recovered will be proportionately reduced and the drilled PUD Wells
will be released from the lien. As of December 31, 2010, the maximum amount of the Drilling
Support Lien had been reduced to $74.1 million. However, after
giving effect to the total number of
wells drilled as of February 28, 2011 (26.83 wells, calculated as
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provided
in the Development Agreement), the maximum amount of the Drilling
Support Lien would
be reduced to approximately $44.0 million.
The trust is not responsible for any costs related to the drilling of development wells or any
other development or operating costs. The trusts cash receipts in respect of the Royalties are
determined after deducting post-production costs and any applicable taxes associated with the
Royalties, and the trusts cash available for distribution includes cash receipts from its hedging
contracts and are reduced by trust administrative expenses and expenses incurred as a result of
being a publicly traded entity. Post-production costs generally consist of costs incurred to
gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any
charge payable to ECA for such post-production costs on its Greene County Gathering System is
limited to $0.52 per MMBtu gathered until ECA has fulfilled its drilling obligation (the
Post-Production Services Fee); thereafter, ECA may increase the Post-Production Services Fee to
the extent necessary to recover certain capital expenditures in the Greene County Gathering System.
As of December 31, 2010, the total gas reserves estimated to be attributable to the trust
interests were 102.4 Bcf. This amount includes 59.9 Bcf of proved undeveloped reserves and 42.5 Bcf
of proved developed reserves.
ECAs retained interest in the Underlying Properties entitles it to 10% of the proceeds from
the sale of natural gas from the Producing Wells as well as 50% of the proceeds from the sale of
production from the PUD Wells. ECA on average owns an 81.53% net revenue interest in the
Producing Wells. Please read
Description of the royalties below. ECA operates all of the Producing Wells and has agreed to operate not less than
90% of the PUD Wells during the subordination period as defined below. In addition, ECA has agreed
to operate the gas properties to which the Royalties relate and to cause to be marketed natural gas
produced from these properties in the same manner it would if such properties were not burdened by
the Royalties.
Generally, the percentage of production proceeds received by the trust with respect to a well
equals the product of (i) the percentage of proceeds to which the trust is entitled under the terms
of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by (ii) ECAs
net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in the
Producing Wells. Therefore, the trust is entitled to receive on average 73.37% of the proceeds of
production from the Producing Wells. With respect to a PUD Well, the conveyance related to the PUD
Royalty Interest provides that the proceeds from the PUD Wells are calculated on the basis that the
underlying PUD Wells are burdened only by interests that in total would not exceed 12.5% of the
revenues from such properties, regardless of whether the royalty interest owners are actually
entitled to a greater percentage of revenues from such properties. As the applicable net revenue
interest of a well is calculated by multiplying ECAs percentage working interest in such well by
the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a PUD
Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the trust would be
entitled to 43.75% of the production proceeds from such well. To the extent ECAs working interest
in a PUD Well is less than 100%, the trusts share of proceeds would be proportionately reduced.
Pursuant to the Development Agreement, however, ECA will only satisfy its drilling obligation when
it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to
a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the
requirement to drill additional wells to achieve a total of 52 equivalent wells; provided, that ECA
may be required to drill fewer gross development wells due to lateral length of any well or wells
exceeding 2,500 feet.
The trust expects to make quarterly cash distributions of substantially all of its cash
receipts, after deducting trust administrative expenses and the costs incurred as a result of being
a publicly traded entity and reserves therefor, on or about 60 days following the completion of
each quarter through (and including) the quarter ending March 31, 2030 (the Termination Date).
The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16,
2010. The trust will begin to liquidate on the Termination Date and will soon thereafter wind up
its affairs and terminate. At the Termination Date, 50% of each of the PDP Royalty Interest and the
PUD Royalty Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty
Interest and the PUD Royalty Interest will be sold, and the net proceeds therefrom will be
distributed pro rata to the unitholders soon after the Termination Date. ECA will have a right of
first refusal to purchase the remaining 50% of the royalty interests at the Termination Date.
Because payments to the trust will be generated by depleting assets and the trust has a finite
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life with the production from the Underlying Properties diminishing over time, a portion of
each distribution will represent a return of your original investment.
The business and affairs of the trust are managed by The Bank of New York Mellon Trust
Company, N.A. as Trustee. Although ECA operates all of the Producing Wells and substantially all of
the PUD Wells, ECA has no ability to manage or influence the management of the trust.
TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
Subordination and Incentive Thresholds
ECA has calculated quarterly target levels of cash distributions for the life of the trust,
such levels having been set forth in the initial prospectus used in the initial public offering (Initial Prospectus). The amount of the quarterly
distributions may fluctuate from quarter to quarter, depending on the proceeds received by the
trust, among other factors.
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.
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.
In order to provide support for cash distributions on the common units, ECA subordinated
4,401,250 of the trust units it retained following the initial public offering, which constitute
25% of the outstanding trust units. While the subordinated units are entitled to receive pro rata
distributions from the trust each quarter 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 for such quarter 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 (each, a
subordination threshold). In exchange for agreeing to subordinate these trust units, and in order
to provide additional financial incentive to ECA to perform its drilling obligation and operations
on the Underlying Properties in an efficient and cost-effective manner, ECA is entitled to receive
incentive distributions (the incentive distributions) equal to 50% of the amount by which the
cash available for distribution on all of the trust units in any quarter exceeds 150% of the
subordination threshold for such quarter (which is 120% of the target distribution for such
quarter) (each, an incentive threshold).
ECA has incurred costs of approximately $5 million in establishing the floor price contracts
being transferred to the trust. ECA is entitled to reimbursement for these expenditures, plus
interest at 10% per annum, only if and to the extent distributions to trust unitholders would
otherwise exceed the incentive threshold. This reimbursement is deducted, over time, from the 50%
of cash available for distribution in excess of the incentive thresholds otherwise payable to the
trust unitholders. ECAs right to receive the remaining 50% of such cash in the form of incentive
distributions would not be affected.
The subordinated units will automatically convert into common units on a one-for-one basis and
ECAs right to receive incentive distributions and to recoup the reimbursement amount will
terminate, at the end of the fourth full calendar quarter following ECAs satisfaction of its
drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the floor price contracts to be transferred to the trust. The Trust currently
expects that ECA will complete its drilling obligation on or before March 31, 2013 and that,
accordingly, the subordinated units will convert into common units on or before March 31, 2014. In
the event of delays, it will have until March 31, 2014 under its contractual obligation to drill
all the PUD Wells, in which event the subordinated units would convert into common units on or
before March 31, 2015. The period during which the subordinated units are outstanding is referred
to as the subordination period.
The table below sets forth the target distributions and subordination and incentive thresholds
for each calendar quarter through the first quarter of 2015.
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Subordination | Target | Incentive | ||||||||||
Period | Threshold | Distribution(1) | Threshold | |||||||||
(per unit) | ||||||||||||
2011: |
||||||||||||
First Quarter |
$ | 0.446 | $ | 0.558 | $ | 0.669 | ||||||
Second Quarter |
0.451 | 0.564 | 0.676 | |||||||||
Third Quarter |
0.550 | 0.688 | 0.825 | |||||||||
Fourth Quarter |
0.565 | 0.706 | 0.847 | |||||||||
2012: |
||||||||||||
First Quarter |
0.574 | 0.717 | 0.861 | |||||||||
Second Quarter |
0.602 | 0.752 | 0.903 | |||||||||
Third Quarter. |
0.624 | 0.780 | 0.937 | |||||||||
Fourth Quarter |
0.701 | 0.876 | 1.051 | |||||||||
2013: |
||||||||||||
First Quarter |
0.756 | 0.945 | 1.135 | |||||||||
Second Quarter |
0.754 | 0.942 | 1.131 | |||||||||
Third Quarter |
0.701 | 0.876 | 1.052 | |||||||||
Fourth Quarter |
0.659 | 0.824 | 0.989 | |||||||||
2014: |
||||||||||||
First Quarter |
0.610 | 0.763 | 0.915 | |||||||||
Second Quarter |
0.589 | 0.736 | 0.883 | |||||||||
Third Quarter |
0.571 | 0.713 | 0.856 | |||||||||
Fourth Quarter |
0.549 | 0.687 | 0.824 | |||||||||
2015: |
||||||||||||
First Quarter |
0.519 | 0.649 | 0.779 |
(1) | Target Distributions do not represent minimum quarterly distributions. There is no guarantee that the Trust will pay distributions at the target distribution level in any quarter. |
For additional information with respect to the subordination and incentive thresholds,
please see Target distributions and subordination and incentive thresholds and Description of
the royalties.
ENERGY CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the exploration, development, production,
gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf
Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors
have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and
ECA is one of the largest natural gas operators in the Appalachian Basin. 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.
ECA was formed in September 1992 as a Colorado corporation and subsequently reincorporated in
West Virginia through a merger with ECAs predecessor in June 1995. ECAs predecessor began
operating in the Appalachian Basin in 1963. ECAs principal offices are located at 4643 South
Ulster Street, Suite 1100, Denver, Colorado 80237, and its telephone number is (303) 694-2667. ECA
is required to deliver to the Trustee a statement of the computation of the proceeds for each
computation period, as well as quarterly drilling and production results. ECA is not a reporting
company and does not file periodic reports with the SEC. Therefore, as a trust unitholder, you do
not have access to financial information of ECA.
The trust units do not represent interests in or obligations of ECA.
FORMATION TRANSACTIONS
At the closing of the initial public offering on July 7, 2010, the following transactions,
which are referred to as the formation transactions, occurred:
| ECA conveyed 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 ECAs interest in the Producing Wells (after deducting post-production costs and any applicable taxes) for a period of 20 years |
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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 ECAs 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 approximately $161 million. The Term PDP Royalty and the Term PUD Royalty are collectively referred to as the Term Royalties. | |||
| ECA and the Private Investors conveyed 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 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 ECAs 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, 3,087,371 common units constituting 17.5% of the trust units outstanding and 4,401,250 subordinated units constituting 25% of the trust units outstanding, and in the case of the Private Investors, 1,313,879 common units constituting 7.5% of the trust units outstanding. The Perpetual PDP Royalty and the Perpetual PUD Royalty are collectively referred to as the Perpetual Royalties. | ||
| The trust sold 8,802,500 common units to the public, representing a 50.0% interest in the trust. | ||
| ECA conveyed to the trust the natural gas floor price contracts and entered into a back-to-back swap agreement with the trust providing the trust with the benefit of the swap contracts entered into between ECA and third parties. | ||
| ECAs subsidiary conveyed the Term Royalties to the trust in exchange for a payment from the net proceeds from the initial public offering and used the net proceeds to repay all of the demand note to ECA and the remaining net proceeds were distributed to ECA. | ||
| ECA purchased 209,312 common units from the Private Investors at the initial offering price. | ||
| ECA and the trust entered into an Administrative Services Agreement outlining the provision of administrative services to the trust and its compensation therefor and a Development Agreement outlining ECAs drilling obligation to the trust with respect to the PUD Wells. Please see The Trust Administrative Services Agreement and Development Agreement. | ||
| ECA granted to the trust the Drilling Support Lien. | ||
| ECA granted to the trust a lien on the PDP Royalty Interest and the PUD Royalty Interest (the Royalty Interest Lien) to provide protection to the trust, in the event of a bankruptcy of ECA, against the risk that the Royalties were not considered a real property interest. |
On July 21, 2010, the Trust sold an additional 294,950 common units pursuant to the
underwriters over-allotment option.
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KEY INVESTMENT CONSIDERATIONS
The following are some key investment considerations related to the Royalties and the
common units:
| Royalties not burdened by operating or capital costs. The trust is not responsible for any operating or capital costs associated with the Underlying Properties, including the costs to drill the PUD Wells. As a result, the trusts burden to pay costs associated with any particular well will not arise until such well is producing natural gas attributable to the trusts 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 is obligated to reimburse ECA for approximately $5 million plus interest at 10% per annum incurred in establishing the floor price contracts transferred to the trust if and to the extent cash available for distribution by the trust exceeds certain levels. | ||
| Downside protection against natural gas price volatility through natural gas hedging contracts for approximately 50% of estimated production through March 31, 2014. The trust has entered into swap hedging contracts covering approximately 50% of the expected production volumes attributable to the trust from April 1, 2010 through March 31, 2014. The swap contracts relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per MMBtu for the period from April 1, 2010 through June 2012. The price of the floor price hedging contracts is $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: |
| A portion of the trust units that ECA owns, constituting 25% of the outstanding trust units, are subordinated units that are not entitled to receive distributions unless there is sufficient cash to pay the subordination threshold to the common units. These subordinated units only convert into common units upon completion of the subordination period and are not being offered hereby. | ||
| To the extent that the trust has cash available for distribution in excess of the incentive thresholds during the subordination period, ECA is entitled to receive 50% of such cash as incentive distributions and 50% of such cash as recoupment of its costs for establishing the floor price contracts until it has recouped approximately $5 million plus interest at 10% per annum. | ||
| ECA is 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 is expected to offset depletion of the Producing Wells in the near term. | ||
| ECAs experience and position as Marcellus Shale operator. Since January 1, 2006, ECA has drilled over 180 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 42 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 has agreed to operate not less than 90% of the PUD Wells during the subordination period, allowing ECA to control |
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the timing and amount of discretionary expenditures for operational and development activities with respect to substantially all of the PUD Wells. ECAs 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. | |||
| Experience of ECA marketing natural gas production. As the operator of all of the Producing Wells and substantially all the PUD Wells, ECA has the responsibility to market or cause to be marketed the natural gas production related to the Underlying Properties. | ||
| 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. |
KEY RISK FACTORS
Trust Units are inherently different from the capital stock of a corporation, although many of
the business risks to which the trust is subject are similar to those that would be faced by a
corporation engaged in a similar business Below is a summary of certain key risk factors for
consideration related to the Royalties and the common units. This list is not exhaustive, please
also read carefully the full discussion of these risks and other risks described under Risk
factors on page 11. Before you invest in trust units, you should carefully consider these risk
factors. You should also consider all of the other information included in this prospectus and the
other documents incorporated herein by reference in evaluating an investment in our common units.
| Drilling and completion of the PUD Wells are high risk activities with many uncertainties that could delay ECAs anticipated drilling schedule and adversely affect future production from the Underlying Properties. Any such delays or reductions in production could decrease future revenues that are available for distribution to unitholders. | ||
| Natural gas prices fluctuate due to a number of factors that are beyond the control of the Trust and ECA, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders. | ||
| Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the trust units. | ||
| The generation of proceeds for distribution by the Trust depends in part on gathering, transportation and processing facilities owned by ECA and others. Any limitation in the availability of those facilities could interfere with sales of natural gas production from the Underlying Properties. | ||
| Due to the Trusts lack of industry and geographic diversification, adverse developments in the Trusts existing area of operation could adversely impact its financial condition, results of operations and cash flows and reduce its ability to make distributions to the unitholders. | ||
| The natural gas reserves estimated to be attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and gas properties or royalty interests to replace the depleting assets and production. | ||
| The amount of cash available for distribution by the Trust will be reduced by the amount of post-production costs, applicable taxes associated with the Trusts interest, Trust expenses, incentive distributions and reimbursement obligations payable to ECA. |
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| The ability of ECA to satisfy its obligations to the Trust depends on the financial position of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in the event of ECAs bankruptcy, it may be expensive and time-consuming for the Trust to exercise its remedies. | ||
| Federal and state legislative and regulatory initiatives relating to hydraulic fracturing or drilling operations generally could result in increased costs and additional operating restrictions or delays as well as adversely affect ECAs services. |
| The Trusts 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. |
| If the Trust were subjected to a material amount of additional entity-level taxation by Pennsylvania or any other states, the Trusts cash available for distribution to you would be reduced. |
PROVED RESERVES
Proved reserves of the Royalties. The following table sets forth certain estimated proved
reserves, estimated future net cash flows and the discounted present value thereof attributable to
the Royalties as of December 31, 2010, in each case derived from the reserve report. The reserve
report was prepared by Ryder Scott in accordance with criteria established by the Securities and
Exchange Commission, or SEC. In accordance with the SECs 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 January 1, 2010 through December 1, 2010, without giving effect to the
derivative transactions, and were held constant for the life of the properties. This yielded a
price for natural gas of $4.65 per Mcf. Proved reserve quantities attributable to the Royalties are
calculated by multiplying the gross reserves for each property less fuel usage and line loss by the
royalty interest assigned to the Trust in each property. The net cash flows attributable to the
trusts reserves are net of the trusts obligation to reimburse ECA for post-production costs. The
reserves and cash flows attributable to the trusts interests include only the reserves
attributable to the Royalties that are expected to be produced within the 20-year period in which
the trust owns the royalty interest as well as the 50% residual interest in the reserves that the
trust will own on the Termination Date. A summary of the reserve report is included as Annex A to
this prospectus.
Proved Gas | Estimated Future | Discounted Estimated | ||||||||||
Proved Reserves | Reserves (Bcf) | Net Cash Flows | Future Net Cash Flows (1) | |||||||||
(Dollars in thousands) | ||||||||||||
Royalty Interests: |
||||||||||||
Proved Developed (2) |
42.486 | $ | 174,607 | $ | 98,757 | |||||||
Proved Undeveloped |
59.963 | 246,430 | 132,485 | |||||||||
Total |
102.449 | $ | 421,037 | $ | 231,242 | |||||||
(1) | The present values of future net cash flows for the Royalties were determined using a discount rate of 10% per annum. | |
(2) | Includes reserves currently behind pipe in wells which are in the process of being completed. |
Annual production attributable to royalty
interests. The following bar graph shows estimated annual
production, as of December 20, 2010, from the Royalties based on the pricing
and other assumptions set forth in the reserve report dated December
20,
2010. The production estimates include the impact of additional
production that is as a result of the drilling of the PUD Wells. This chart
is presented to show the anticipated decline curve on the
Trusts reserves.
The target distributions and incentive thresholds were prepared based
on the reserve report dated May 26, 2010, as a result the estimated
annual production presented in this graph differs from the estimates
used in establishing the target distributions and subordination and
incentive thresholds set forth herein.
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THE OFFERING
Common units offered to public
|
2,525,000 units |
|
Total units outstanding after the offering
|
13,203,750 common units and 4,401,250 subordinated units | |
Use of proceeds
|
The trust will not receive any of the proceeds from the sale of the common units by ECA | |
NYSE symbol
|
ECT | |
Trustee
|
The Bank of New York Mellon Trust Company, N.A. | |
Quarterly cash distributions
|
Actual cash distributions to the trust unitholders will fluctuate quarterly based on the quantity of natural gas produced from the Underlying Properties, the prices received for natural gas production and other factors. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties initially increasing and subsequently diminishing over time, a portion of each distribution will represent a return of your original investment and the target distributions will decline over time. Production declines are expected to be offset in the near term by production realized from the drilling and successful completion of the PUD Wells. | |
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. | ||
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 right of first 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 trusts 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. |
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Estimated ratio of taxable income to
distributions
|
The Trust estimates that if you own units you purchase in this offering through the record date for distributions for the period ending December 31, 2013, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately 65% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $2.50 per unit, the trust estimates that your average allocable federal taxable income per year will be no more than approximately $1.63 per unit. Please read Federal income tax considerations. |
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RISK FACTORS
Trust units are inherently different from the capital stock of a corporation, although many of
the business risks to which the Trust is subject are similar to those that would be faced by a
corporation engaged in a similar business. Before you invest in trust units, you should carefully
consider the risk factors described below. You should also consider all of the other information
included in this prospectus and the other documents incorporated herein by reference in evaluating
an investment in the common units.
If any of the risks discussed in the foregoing documents were actually to occur, the trusts
financial condition, results of operations, or cash flow could be materially adversely affected. In
that case, the trusts ability to make distributions to its trust unitholders may be reduced, the
trading price of the trust units could decline and you could lose all or part of your investment.
Drilling and completion of the PUD Wells are high risk activities with many uncertainties that
could delay ECAs anticipated drilling schedule and adversely affect future production from the
Underlying Properties. Any such delays or reductions in production could decrease future revenues
that are available for distribution to unitholders.
The drilling and completion of the PUD Wells on the Underlying Properties are subject to
numerous risks beyond ECAs and the Trusts control, including risks that could delay ECAs current
drilling schedule for the PUD Wells and the risk that drilling will not result in commercially
viable natural gas production. ECAs 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. ECAs 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, ECAs 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, but not limited to, the following:
| delays imposed by or resulting from compliance with regulatory requirements including permitting; | ||
| unusual or unexpected geological formations; | ||
| shortages of or delays in obtaining equipment and qualified personnel; | ||
| equipment malfunctions, failures or accidents; | ||
| lack of available gathering facilities or delays in construction of gathering facilities; | ||
| lack of available capacity on interconnecting transmission pipelines; | ||
| unexpected operational events and drilling conditions; | ||
| pipe or cement failures; | ||
| casing collapses; | ||
| lost or damaged drilling and service tools; | ||
| loss of drilling fluid circulation; | ||
| uncontrollable flows of natural gas and fluids; | ||
| fires and natural disasters; | ||
| environmental hazards, such as natural gas leaks, pipeline ruptures and discharges of toxic gases; | ||
| adverse weather conditions; | ||
| reductions in natural gas prices; | ||
| natural gas property title problems; and | ||
| market limitations for natural gas. |
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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 Trusts reserves and quarterly cash distributions are highly dependent upon the prices
realized from the sale of natural gas. Natural gas prices can fluctuate widely on a month-to-month
basis in response to a variety of factors that are beyond the control of the Trust and ECA. These
factors include, among others:
| weather conditions and seasonal trends; | ||
| regional, domestic and foreign supply and perceptions of supply of natural gas; | ||
| availability of imported liquefied natural gas, or LNG; | ||
| the level of demand and perceptions of demand for natural gas; | ||
| anticipated future prices of natural gas, LNG and other commodities; | ||
| technological advances affecting energy consumption and energy supply; | ||
| U.S. and worldwide political and economic conditions; | ||
| the price and availability of alternative fuels; | ||
| the proximity, capacity, cost and availability of gathering and transportation facilities; | ||
| the volatility and uncertainty of regional pricing differentials; | ||
| acts of force majeure; | ||
| governmental regulations and taxation; and | ||
| energy conservation and environmental measures. |
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 Trusts royalty interests. The Trusts reserve quantities and revenues are
based on estimates of reserve quantities and revenues for the Trust. See The RoyaltiesNatural
gas reserves of this prospectus 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:
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| historical production from the area compared with production rates from other producing areas; | ||
| natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and | ||
| the assumed effect of governmental regulation. |
Changes in these assumptions or actual production costs incurred and results of actual
development and production costs could materially decrease reserve estimates.
In particular, reserve estimates for fields that do not have a lengthy production history are
less reliable than estimates for fields with lengthy production histories. A lack of production
history may contribute to inaccuracy in estimates of proved reserves, future production rates and
the timing of development expenditures. The Producing Wells have been operational for approximately
one year. Furthermore, 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.
The generation of proceeds for distribution by the Trust depends in part on gathering,
transportation and processing facilities owned by ECA and others. Any limitation in the
availability of those facilities could interfere with sales of natural gas production from the
Underlying Properties.
The amount of natural gas that may be produced and sold from any well to which the Underlying
Properties relate is subject to curtailment in certain circumstances, such as by reason of weather
conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of
tendered gas to meet quality specifications of gathering lines or downstream transporters,
excessive line pressure which prevents delivery of gas, physical damage to the gathering system or
transportation system or lack of contracted capacity on such systems. The curtailments may vary
from a few days to several months. In many cases, ECA is provided limited notice, if any, as to
when production will be curtailed and the duration of such curtailments. If ECA is forced to reduce
production due to such a curtailment, the revenues of the Trust and the amount of cash
distributions to the Trust unitholders would similarly be reduced due to the reduction of proceeds
from the sale of production.
Some of the wells on the underlying PUD properties will be drilled in locations that currently
are not serviced by gathering and transportation pipelines or locations in which existing gathering
and transportation pipelines do not have sufficient capacity to transport additional production. As
a result, ECA may not be able to sell the natural gas production from certain PUD Wells until the
necessary gathering systems and/or transportation pipelines are constructed or until the necessary
transportation capacity on an interstate pipeline is obtained. Any delay in the construction or
expansion of these gathering systems beyond the currently estimated construction schedules, or a
delay in the procurement of additional transportation capacity would delay the receipt of any
proceeds that may be associated with natural gas production from the PUD Wells. If transportation
capacity is not available, either directly from a pipeline or pipelines or in the secondary
capacity market, ECA would be required to request that the pipeline or pipelines construct
additional facilities or expand their existing facilities to provide additional transportation
capacity. The pipelines are not required to undertake such construction or expansion. If the
pipeline refuses to construct additional transportation capacity or expand its existing
transportation capacity, ECA may not be able to receive proceeds that may be associated with
natural gas production from wells on the underlying PUD properties. Any delay in the construction
or expansion of pipeline transportation facilities will delay the receipt of any proceeds that may
be associated with natural gas production from wells on the underlying PUD properties.
The generation of proceeds for distribution by the Trust depends in part on the ability of ECA
and/or its customers to obtain service on transportation facilities owned by third party pipelines;
any limitation in the availability of those facilities and/or any increase in the cost of service
on those facilities could interfere with sales of natural gas production from the Underlying
Properties.
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Natural gas that is gathered on the Greene County Gathering System, including natural gas
produced from the Underlying Properties, is currently shipped on two interstate natural gas
transportation pipelines. ECAs 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 recently executed a binding precedent agreement with a third party to provide firm
transportation downstream of ECAs Greene County Gathering System for 50,000 Dth per day. This firm
transportation arrangement is scheduled to be in service August 1, 2011 and will be at the third
partys filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor.
This is a post-production cost which will ensure downstream capacity and such costs will be charged
to the Trusts interest.
ECA may, in the future, seek to obtain additional firm transportation capacity, but there can
be no assurance that capacity will be available. In addition, to the extent ECAs 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 Trusts 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 ECAs ability to perform the drilling obligations and delay completion
of the development wells, which would reduce future distributions to Trust unitholders.
Due to the Trusts lack of industry and geographic diversification, adverse developments in
the Trusts 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 Trusts interests to operational and regulatory
risk in that area. Due to the lack of diversification in industry type and location of the Trusts
interests, adverse developments in the natural gas market or the area of the Underlying Properties
could have a significantly greater impact on the Trusts financial condition, results of operations
and cash flows than if the Trusts 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 preliminary title reviews on the PUD
Wells that have not been drilled. Prior to the drilling of each new PUD Well, ECA intends to obtain a preliminary title review to
ensure there are no obvious defects
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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. ECAs 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 has 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 ECAs activities or operations of the gas
properties. In addition, pursuant to the Administrative Services Agreement and the Development
Agreement, up to 10% of the PUD Wells may be operated by third parties unrelated to ECA until
completion of ECAs drilling obligation, after which ECA may transfer operations of any or all of
the Trust properties. Such third party operators may not have the operational expertise of ECA
within the AMI. Gas properties are typically managed pursuant to an operating agreement among the
working interest owners in the properties. The typical operating agreement contains procedures
whereby the owners of the working interests in the property designate one of the interest owners to
be the operator of the property. Under these arrangements, the operator is typically responsible
for making all decisions relating to drilling activities, sale of production, compliance with
regulatory requirements and other matters that affect the property. Neither the Trustee nor the
Trust unitholders has any contractual ability to influence or control the field operations of, sale
of natural gas from, or future development of, the Underlying Properties. The trust units are a
passive investment that entitle the Trust unitholder to only receive cash distributions from the
royalty interests and hedging contracts that have been established for the benefit of the Trust.
ECA may sell all or a portion of the Underlying Properties, subject to and burdened by the
Royalties, after satisfying its drilling obligations to the Trust; any such purchaser could have a
weaker financial position and/or be less experienced in natural gas development and production than
ECA.
Trust unitholders will not be entitled to vote on any sale of the Underlying Properties if the
Underlying Properties are sold subject to and burdened by the Royalties and the Trust will not
receive any proceeds from any such sale. The purchaser would be responsible for all of ECAs
obligations relating to the Royalties on the portion of the Underlying Properties sold, 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 Royalties. Any
purchaser, 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 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 Royalties 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 original reserve report described in the Initial Prospectus, the gas
production from proved producing reserves attributable to the PDP Royalty Interest is projected to
decline at an average rate of approximately 8.5% per year over the life of the Trust. As a PUD Well
is drilled and placed on production, the production rate is expected to decline approximately 37.3%
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 ECAs commitment to drill the PUD Wells, ECA has
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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 provides that the Trusts business activities are limited to owning the
Royalties and any activity reasonably related to such ownership, including activities required or
permitted by the terms of the conveyances related to the Royalties. As a result, the Trust is not
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 Trusts interest, Trust expenses,
incentive distributions and reimbursement obligations payable to ECA.
The Royalties and the Trust bear certain costs and expenses that reduce the amount of cash
received by or available for distribution by the Trust to the holders of the trust units. These
costs and expenses include those described below.
| Substantially all of the production from the Producing Wells and the PUD Wells utilize ECAs Greene County Gathering System. The Trust pays the initial Post-Production Services Fee to ECA for use of such system, which includes ECAs costs to gather, compress, transport, process, treat, dehydrate and market the gas. This fee is fixed until ECAs obligation to drill the PUD Wells is satisfied; thereafter, ECA may increase this fee to the extent necessary to recover certain capital expenditures on the Greene County Gathering System, provided the resulting charge does not exceed the prevailing charges in the area for similar services. Additionally, the Trust is charged for the cost of fuel used in the compression process or equivalent electricity charges when electric compressors are used. | ||
| Any third party post-production costs incurred in the future and associated with the Trusts interests will reduce cash received by or available for distribution, including any amounts paid by ECA for transportation on downstream interstate pipelines. Such post-production costs will include the costs to be incurred in connection with the agreement ECA has recently entered into with a third party to obtain firm transportation downstream of ECAs Greene County Gathering System for 50,000 Dth per day at the third partys filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor. | ||
| Taxes allocated to or imposed on the Trust include Pennsylvania franchise tax and any applicable property, ad valorem, production, severance, excise and other similar taxes. Currently, there are no taxes in Pennsylvania related to the production or severance of oil and natural gas in Pennsylvania, but there are currently proposals pending in both the Pennsylvania Senate Finance and the House Energy and Environmental Resources Committees to enact a severance tax, and lawmakers may propose other taxes in the future. If adopted, such taxes would be a post-production cost that is borne by the Trust. | ||
| The Trust bears 100% of Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee and an annual administrative services fee of $60,000 payable to ECA. | ||
| The Trust is also responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees and registrar and transfer agent fees. | ||
| ECA is entitled, during the subordination period, to receive a quarterly incentive distribution from the Trust in an amount equal to 50% of the amount by which distributions paid to all unitholders exceed the incentive thresholds described herein. A more detailed description of these |
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distributions is set forth under the caption Target Distributions and Subordination and Incentive Thresholds in this prospectus. | |||
| ECA incurred costs of approximately $5 million in establishing the floor price contracts transferred to the Trust. ECA is entitled to recover the Reimbursement Amount only if and to the extent distributions to Trust unitholders would otherwise exceed the incentive threshold. This reimbursement will be deducted, over time, from the 50% of cash available for distribution in excess of the incentive thresholds otherwise payable to the common and subordinated unitholders. ECAs reimbursement right will terminate at the end of the subordination period. |
The amount of costs and expenses that will be borne by the Trust may vary materially from
quarter-to-quarter. The extent by which the costs and expenses described above are higher or lower
in any quarter will directly decrease or increase the amount received by the Trust and available
for distribution to the unitholders. For a further summary of post-production costs and applicable
taxes for the producing lives of the Producing Wells and PUD Wells,
see The RoyaltiesMarketing and Post-production services of this
prospectus. 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 ECAs natural gas production usually exceed the relevant benchmark
prices, such as NYMEX, that are used for calculating hedge positions. The difference between the
price received and the benchmark price is called a basis differential. The differential may vary
significantly due to market conditions, the quality and location of production and other factors.
ECA cannot accurately predict natural gas differentials. Decreases in the differential between the
realized price of natural gas and the benchmark price for natural gas could reduce the proceeds to
the Trust and therefore the cash distributions by the Trust and the value of the trust units.
ECA has entered into natural gas floor price contracts for the benefit of the Trust and has
entered into a back-to-back swap agreement with the Trust that cover only a portion of the
estimated natural gas production attributable to the Royalties, and such hedging arrangements will
terminate after March 31, 2014. The Trusts 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 Royalties is hedged
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 Trusts ability to realize cash flow from
natural gas price increases on the portion of the production attributable to the Royalties that is
hedged. The Trust will not have any ability to terminate the swaps before the expiration date.
The Trusts counterparties under the natural gas floor price contracts are Wells Fargo
Foothill, Inc. and BP Energy Company, and its counterparty under the back-to-back swap agreement is
ECA, whose counterparties are also Wells Fargo Foothill, Inc. and BP Energy Company. 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 has no continuing
obligation with respect to the natural gas floor price contracts. However, ECA is the Trusts
counterparty under the back-to-back swap agreement and has continuing obligations with respect to
this agreement.
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,
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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, ECAs 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 unitholders will in
fact receive any specified return on an 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 ECAs
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.
Actual
cash distributions may differ materially from the target
distributions due to
significant
business, economic, financial, legal, regulatory and competitive risks and uncertainties.
The target distributions subordination thresholds and incentive
thresholds, as set forth in the Initial Prospectus under the caption Target Distributions and
Subordination and Incentive Thresholds, are based on ECAs calculations, and ECA has not received
an opinion or report on such calculations from any independent accountants. Such calculations, as
established and set forth in the Initial Prospectus, were 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 settled NYMEX pricing for April, May and June 2010 of
$3.842, $4.271 and $4.155 per MMBtu, respectively, and NYMEX forward pricing as of June 4, 2010 for
the thirty three 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 2027; however,
actual sales prices may be significantly lower. Additionally, these estimates assume that the PUD
Wells will be drilled on ECAs current anticipated schedule and the related Underlying Properties
will achieve production volumes set forth in the reserve report; however, the drilling of the PUD
Wells may be delayed and actual production volumes may be
significantly lower. As a result, actual distributions may differ
materially from the target distributions.
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 Royalties 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.
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The Trustee must sell the Royalties if unitholders approve the sale or vote to dissolve the
Trust. The Trustee must also sell the Royalties if the gross proceeds to the Trust attributable to
the Royalties and hedge agreements (after deducting any amounts owed to ECA pursuant to the natural
gas swap agreements) are less than $1.5 million for any four consecutive quarters. Sale of all the
Royalties 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 right of first refusal to purchase the
Perpetual Royalties at the Termination Date. A more detailed description of this right of first
refusal is set forth in this prospectus under the caption The Trust.
Conflicts of interest could arise between ECA and the Trust unitholders.
As a working interest owner in the Underlying Properties, ECA could have interests that
conflict with the interests of the Trust and the Trust unitholders. For example:
| Notwithstanding its drilling obligation to the Trust, ECAs interests may conflict with those of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of the Underlying Properties. Additionally, ECA may abandon a well which is uneconomic to it while such well is still generating revenue for the Trust unitholders. Subsequent to fulfilling its drilling obligation, ECA may make decisions with respect to expenditures and decisions to allocate resources on projects in other areas that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause gas production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future. 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. | ||
| ECA may sell some or all of the Underlying Properties, subject to its obligation not to sell any of the underlying PUD properties prior to satisfying its obligation to drill the PUD Wells. Such sale may not be in the best interests of the Trust unitholders. Any purchaser may lack ECAs experience in the Marcellus Shale or its credit worthiness. | ||
| ECA may, without the consent of the Trust unitholders, require the Trust to release royalty interests with an aggregate value to the Trust of up to $5.0 million during any 12-month period. These releases will be made only in connection with the sale by ECA of the Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust of such royalty interests. See The RoyaltiesSale and Abandonment of Underlying Properties in this prospectus. | ||
| After it has completed its drilling obligation, ECA may in its discretion increase its Post-Production Services Fee for post-production costs on its Greene County Gathering System to the extent necessary to recover certain capital expenditures on the Greene County Gathering System. | ||
| ECA is permitted under the conveyance agreements creating the Royalties to enter into new processing and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and ECA will deduct from the Trusts proceeds any charges under |
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such contracts attributable to production from the Trust properties. Provisions in the conveyance agreements, however, require that charges under future contracts with affiliates of ECA relating to processing or transportation of natural gas must be comparable to charges prevailing in the area for similar services. | |||
| ECA has registration rights and can sell its units without considering the effects such sale may have on common unit prices or on the Trust itself. Additionally, ECA can vote its trust units in its sole discretion. |
The Trust is managed by a Trustee who cannot be replaced except at a special meeting of Trust
unitholders.
The business and affairs of the Trust are 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 Royalties, and ECAs
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
unitholders 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.
ECAs 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. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon
in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids
as a result of drilling activities in the Marcellus Shale, there has been a variety of regulatory
initiatives at the federal and state level to restrict oil and gas drilling operations in certain
locations. Any increased regulation or suspension of oil and gas exploration and production, or
revision or reinterpretation of existing laws and regulations, that arises out of these incidents
or otherwise could result in delays and higher operating costs. Such costs or significant delays
could have a material adverse effect on ECAs business, financial condition and results of
operations. ECA must also comply with laws and regulations prohibiting fraud and market
manipulations in energy
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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 Trusts 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 ECAs
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 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. Additionally, the Pennsylvania Environmental
Quality Board recently finalized in 2011
amendments to Pennsylvanias oil and gas regulations to update existing requirements regarding the
drilling, casing, cementing, testing, monitoring and plugging of oil and gas wells, and the
protection of water supplies, including reporting the list of chemicals used in hydraulic
fracturing or to stimulate the well. In addition, these regulations specify response actions that must be taken in the event of a report
of gas migration from a well bore. These regulations could lead to significantly increased
production costs and could otherwise impede operations.
Additionally, state and federal regulatory authorities may expand or alter applicable pipeline
safety laws and regulations, compliance with which may require increased capital costs on the part
of ECA and third party downstream natural gas transporters. These and other potential regulations
could increase ECAs operating costs, reduce ECAs liquidity, delay ECAs operations, increase
direct and third party post production costs associated with the Trusts interests or otherwise
alter the way ECA conducts its business, which could have a material adverse effect on ECAs
financial condition, results of operations and cash flows and which could reduce cash received by
or available for distribution, including any amounts paid by ECA for transportation on downstream
interstate pipelines.
The ability of ECA to satisfy its obligations to the Trust depends on the financial position
of ECA, and in the event of a default by ECA in its obligation to drill the PUD Wells, or in the
event of ECAs 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 Development Agreement, ECA is obligated to drill the PUD Wells at its own expense.
ECA is also the operator of all of the Producing Wells and has agreed to operate substantially all
of the PUD Wells until completion of its drilling obligation. The conveyances also provide that ECA
is obligated to market, or cause to be marketed, the natural gas production related to the
Underlying Properties. Additionally, ECA is the counterparty to the Trusts swap agreement and has
continuing obligations with respect to this agreement. Due to the Trusts reliance on ECA to
fulfill these numerous obligations, the value of the Royalties and its ultimate cash available for
distribution will be highly dependent on ECAs performance. ECA is not a reporting company and does
not file periodic reports with the SEC. Therefore, as a Trust unitholder, you do not have access to
financial information of ECA.
The ability of ECA to perform these obligations will depend on ECAs 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.
In the event that ECA defaults on its obligation to drill the PUD Wells, the Trusts remedy
would be to foreclose on the Trusts Drilling Support Lien on all of ECAs 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. As of December 31, 2010, the maximum amount of the
Drilling Support Lien had been reduced to $74.1 million.
However, after giving effect to the total
number of wells drilled as of February 28, 2011 (26.83 wells, calculated as
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provided
in the Development Agreement), the maximum amount of the Drilling Support Lien would be
reduced to approximately $44.0 million. 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 Royalties 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 Royalties might be treated as unsecured claims of the
Trust against ECA in the event of ECAs bankruptcy. The Royalty Interest Lien is intended to
provide security to the Trust should the Royalties 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 Trusts remedy would be to foreclose on the Trusts 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 Royalties 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
Royalties 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 Royalties may be commingled, for a period of time, with proceeds of ECAs
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 ECAs 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 Royalties. During the pendency of ECAs bankruptcy
proceedings, the Trusts 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 ECAs 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.
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 ECAs 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 ECAs operations.
There is inherent risk of incurring significant environmental costs and liabilities in the
performance of ECAs operations due to its handling of petroleum hydrocarbons and wastes, because
of air emissions and wastewater
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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 ECAs wells are drilled and
facilities where ECAs 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 or
to recover some or all of the costs of the removal or remediation of released materials. 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 ECAs 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 ECAs 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 adopted two sets
of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in
emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from
certain large stationary sources under the Prevention of Significant Deterioration (PSD) and
Title V permitting programs, effective January 2, 2011. This stationary source rule tailors
these permitting programs to apply to certain stationary sources in a multi-step process, with the
largest sources first subject to permitting. Facilities required to obtain PSD permits for their
GHG emissions also will be required to reduce those emissions according to best available control
technology standards for GHG that will be established by the states or, in some instances, by the
EPA on a case-by-case basis. The EPAs rules relating to emissions of GHGs from large stationary
sources of emissions are currently subject to a number of legal challenges, but the federal courts
have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring
state environmental agencies to implement, the rules. The EPA has also issued regulations that
require the establishment and reporting of an inventory of GHG emissions from specified stationary
sources, including certain onshore oil and natural gas exploration, development and production
facilities. In addition, the United States Congress has from time to time considered adopting
legislation to reduce emissions of GHGs and almost one-half 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 laws or regulations imposing reporting
obligations on, or otherwise limiting emissions of GHGs from, ECAs 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 Earths
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 ECAs assets and operations.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing
could result in increased costs and additional operating restrictions or delays as well as
adversely affect ECAs services.
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. The process is typically regulated by state oil and
gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic
fracturing involving diesel additives under the Safe Drinking Water Acts
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Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, with results of the study expected to be
available in late 2012, and a committee of the U.S. House of Representatives is also conducting an
investigation of hydraulic fracturing practices. In addition, legislation was introduced in the
recently completed 111th Session of Congress to provide for federal regulation of hydraulic
fracturing and to require disclosure of the chemicals used in the fracturing process, and such
legislation could be introduced and adopted in the current session of Congress. Also, various
state and local governments are considering increased regulatory oversight of hydraulic fracturing
through additional permit requirements, operational restrictions and temporary or permanent bans on
hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For instance,
the New York Department of Environmental Conservation announced in 2010 that the watersheds relied
upon by New York City and Syracuse as sources of drinking water would be excluded from the pending
generic environmental review process, thereby requiring natural gas operators seeking to drill in
either of the watersheds, which are located in the Marcellus Shale region, to pursue a case-by-case
environmental review to establish whether appropriate measures to mitigate potential impacts can be
developed. The Pennsylvania Environmental Quality Board recently
finalized in 2011 amendments to Pennsylvanias
oil and gas regulations to require, among other things, additional information in the stimulation
record including water source identification and volume as well as a list of chemicals used to
stimulate the well, including chemicals used in hydraulic fracturing. These amendments also
affected requirements on drilling, casing, cementing, testing, monitoring, and plugging of oil
and gas wells and specify response actions that must be taken in the event of a report of gas
migration from a well bore. Moreover, in 2010, the Pennsylvania
Department of Environmental Protection adopted a permitting policy concerning surface water
discharges from wastewater treatment facilities handling flowback fluids and produced waters from
oil and gas well sites that could result in increased requirements for treatment of these fluids
and limitations on their discharge to receiving waters. The adoption of any federal or state laws
or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing
process or associated disposal of hydraulic fracturing flowback
fluids and produced waters (which fluids and waters may contain
naturally-occurring radioactive constituents) 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, if ECA is unable to
remove and dispose of water at a reasonable cost and within applicable environmental rules, ECAs
ability to produce gas commercially and in commercial quantities from the Underlying Properties
could be impaired.
Tax Risks Related to the Trusts Common Units
The Trusts tax treatment depends on its status as a partnership for United States federal
income tax purposes. At the inception of the Trust, the Trust received an opinion from tax counsel
that the Trust will be treated as a partnership for United States federal income tax purposes. If
the Internal Revenue Service were to treat the Trust as a corporation for United States 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. At the inception of
the Trust, ECA and the Trust received an opinion from tax counsel that the Trust will be treated as
a partnership for United States federal income tax purposes. In order for the Trust to be treated
as a partnership for United States federal income tax purposes, current law requires that 90% or
more of the Trusts gross income for every taxable year consist of qualifying income, as defined in
Section 7704 of the Internal Revenue Code. The Trust may not meet this requirement or current law
may change so as to cause, in either event, the Trust to be treated as a corporation for United
States federal income tax purposes or otherwise subject the Trust to taxation as an entity.
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. The Trust has not requested, and does not plan to
request, a ruling from the Internal Revenue Service, which we referred to as the IRS, on this or
any other tax matter affecting it.
If the Trust was treated as a corporation for federal income tax purposes, it would pay United
States 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 you, likely causing a substantial reduction in the value of the trust units.
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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 United States federal income tax purposes, the target distribution
amounts may be adjusted to reflect the impact of that law on the Trust.
If the Trust were subjected to a material amount of additional entity-level taxation by
Pennsylvania or any other states, the Trusts cash available for distribution to you would be
reduced.
The Trust will be required to pay Pennsylvania franchise tax on its capital stock value, as
determined pursuant to 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 concerns, several states are evaluating the imposition of entity-level income, franchise, gross receipts, and similar taxes on entities
taxed as partnerships for federal income tax purposes. 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.
Recently proposed severance taxes in Pennsylvania could, if enacted, materially increase the
applicable taxes that are borne by the Trust.
Although Pennsylvania has historically not imposed a severance tax on the production of
natural gas, the Pennsylvania House and Senate recently introduced
similar bills that would impose a
severance tax of 5% of the value of natural gas at the wellhead plus $0.046 per thousand feet of
natural gas severed. The Pennsylvania House has introduced an additional bill that would impose severance tax of
$0.30 per thousand cubic feet of natural gas severed. If this legislation or any future severance tax legislation is adopted, any
such severance tax would be a cost that would be borne by the Trust and could materially reduce
distributions to unitholders.
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 publicly traded partnerships or an investment in our trust units could be
affected by recent and potential legislative, judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The current United States 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, members of Congress previously
considered substantive changes to the existing United States federal income tax laws that affect
certain publicly traded partnerships. Any modification to the United States federal income tax laws
or interpretations thereof could make it difficult or impossible to meet the requirements for the
Trust to be treated as a partnership for United States federal income tax purposes, affect or cause
us to change our business activities, affect the tax considerations of an investment in the Trust,
change the character or treatment of portions of the Trust income and adversely affect an
investment in the Trusts units. Moreover, any modification to the United States federal income tax
laws and interpretations thereof may or may not be applied retroactively. Although the previously
proposed legislation would not appear to have affected the Trusts tax treatment as a partnership, we are
unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any
potential change in law or interpretation thereof could negatively impact the value of an
investment in the trust units.
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary
income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to
long-term capital gains (generally, capital gains on certain assets held for more than 12 months)
of individuals is 15%. However, absent new legislation extending the current rates, beginning
January 1, 2013, the highest marginal U.S. federal income tax rate
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applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and
20%, respectively. Moreover, these rates are subject to change by new legislation at any time.
The recently enacted Patient Protection and Affordable Care Act of 2010, as amended by the
Health Care and Education Reconciliation Act of 2010, is scheduled to impose a 3.8% Medicare tax on
certain net investment income from a variety of sources earned by individuals for taxable years
beginning after December 31, 2012. For these purposes, net investment income generally includes a
Trust unitholders allocable share of the Trust income and gain realized by a Trust unitholder from
a sale of the trust units. The tax will be imposed on the lesser of (i) the Trust unitholders net
income from all investments, or (ii) the amount by which the trust unitholders adjusted gross
income exceeds $250,000 (if the Trust unitholder is married and filing jointly) or $200,000 (if the
Trust unitholder is unmarried).
The Trust prorates 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 unit is transferred.
The Trust prorates 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 unit is transferred. The use of
this proration method may not be permitted under existing Treasury Regulations, and, accordingly,
the Trusts counsel was unable to opine as to the validity of this method. If the IRS were to
challenge this method or new Treasury Regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among the trust unitholders. If the IRS
contests the federal income tax positions the Trust takes, the market for the trust units may be
adversely impacted, the cost of any IRS contest will reduce the Trusts cash available for
distribution to you and items of income, gain, loss and deduction may be reallocated among trust
unitholders.
If the IRS contests the federal income tax positions the Trust takes, the market for the Trust
units may be adversely impacted and the cost of any IRS contest will reduce the Trusts 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 Trusts 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 Trusts counsel or
the positions the Trust takes. A court may not agree with some or all of the conclusions of the
Trusts 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 Trusts
costs of any contest with the IRS will be borne indirectly by the Trust unitholders because the
costs will reduce the Trusts cash available for distribution.
You will be required to pay taxes on your share of the Trusts 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 Trusts 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 Trusts 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 Trusts 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.
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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, some of the Trust
income allocated to organizations exempt from United States federal income tax, including IRAs and
other retirement plans, may be unrelated business taxable income which would be taxable to them.
Distributions to non-U.S. persons may 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 Trusts taxable income.
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 Trusts 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.
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, the trust
unitholder may no longer be treated for United States federal income 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 Trusts 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 Trusts 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 Trusts estimates of the relative fair market values, and the initial tax
bases of the Trusts 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.
It also could affect the amount of gain from unitholders sale of trust units and could have a
negative impact on the value of the trust units or result in audit adjustments to unitholders tax
returns without the benefit of additional deductions.
The sale or exchange of 50% or more of the Trusts capital and profits interests during any
twelve-month period will result in the termination of the Trusts 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
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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 Trusts 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 Trusts taxable year may
also result in more than twelve months of the Trusts taxable income being includable in his
taxable income for the year of termination. A technical termination would not affect the Trusts
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 Obamas Budget Proposal for Fiscal Year 2012 (the
2012 Budget) is the elimination of certain key U.S. federal income tax preferences relating to
natural gas exploration and production. The 2012 Budget proposes to eliminate certain tax
preferences applicable to taxpayers engaged in the exploration or production of natural resources
effective in 2012. Specifically, the 2012 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.
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FORWARD-LOOKING STATEMENTS
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 the trust and other
matters affecting an investment in the common units 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 the activities of the trust are
forward-looking statements.
Such statements may be influenced by factors that could cause actual outcomes and results to
differ materially from those projected. Forward-looking statements are subject to risks and
uncertainties and include statements made in this prospectus under Target distributions and
subordination and incentive thresholds, statements pertaining to future development activities and
costs, and other statements in this prospectus that are prospective and constitute forward-looking
statements.
When used in this document, the words believes, expects, anticipates, intends or
similar expressions are intended to identify such forward-looking statements. The following
important factors, in addition to those discussed elsewhere in this document, could affect the
future results of the energy industry in general, and ECA and the trust in particular, and could
cause those results to differ materially from those expressed in such forward-looking statements:
| risks incident to the drilling and operation of natural gas wells; | ||
| future production and development costs; | ||
| the effect of existing and future laws and regulatory actions; | ||
| the effect of changes in commodity prices, the ability of the trusts hedge counterparties, including ECA, to meet their contractual obligations and conditions in the capital markets; | ||
| competition from others in the energy industry; and | ||
| uncertainty of estimates of natural gas reserves and production. |
This prospectus describes other important factors that could cause actual results to differ
materially from expectations of ECA and the trust, including under the heading Risk factors. All
written and oral forward-looking statements attributable to ECA or the trust or persons acting on
behalf of ECA or the trust are expressly qualified in their entirety by such factors.
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USE OF PROCEEDS
The
trust will not receive any of the proceeds from the sale of the
common units by ECA.
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS
The trusts common units are listed on the New York Stock Exchange (NYSE) under the symbol
ECT. The last reported sale price of the common units on
the NYSE on March 24, 2011 was $31.83. As of
March 24, 2011, there were 17 holders of record of the common units.
Distributions | ||||||||||||||||||||
Unit Price | Per Common | |||||||||||||||||||
Quarter Ended | High | Low | Unit | Record Date | Payment Date | |||||||||||||||
March 31, 2011
(through March 24, 2011) |
$ | 31.98 | $ | 25.50 | $ | (1 | ) | (1 | ) | (1 | ) | |||||||||
December 31, 2010 |
$ | 27.24 | $ | 20.16 | $ | 0.500 | February 14, 2011 | February 28, 2011 | ||||||||||||
September 30, 2010 |
$ | 20.47 | $ | 19.55 | $ | 0.421 | November 15, 2010 | November 30, 2010 | ||||||||||||
June 30, 2010 |
$ | | $ | | $ | 0.272 | (2) | August 16, 2010 | August 31, 2010 |
(1) | The distributions attributable to the quarter ending March 31, 2011 have not yet been declared or paid. | |
(2) | These distributions were in excess of the target distributions for such quarters and as a result ECA received incentive distributions. | |
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ENERGY CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the exploration, development, production,
gathering, aggregation and sale of natural gas and oil, primarily in the Appalachian Basin, Gulf
Coast and Rocky Mountain regions in the United States and in New Zealand. ECA or its predecessors
have owned and operated natural gas properties in the Appalachian Basin for more than 45 years, and
ECA is one of the largest natural gas operators in the Appalachian Basin. 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.
Substantially all of the production subject to the Royalties is gathered by ECAs 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 nine (9) compressors (with 13,295 total horsepower) together with associated processing
equipment. ECAs interconnect agreements with these interstate pipelines currently allow it to
deliver at the interconnections between ECAs facilities and the interstate pipelines up to a total
of 105,000 MMBtu per day for transportation by the interstate pipelines to ECAs customers
(approximately 46,000 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. ECAs predecessor began operating in the Appalachian
Basin in 1963. ECAs principal offices are located at 4643 South Ulster Street, Suite 1100, Denver,
Colorado 80237, and its telephone number is (303) 694-2667. ECA is not a reporting company and does
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.
BENEFICIAL OWNERSHIP OF ECA MARCELLUS TRUST I
The following table sets forth certain information regarding the trust unit ownership of the
trust by each person known to be the beneficial owner of more than 5% of the outstanding trust
units.
Beneficial Ownership | ||||||
Trust Units | ||||||
Trust Units | Percent | |||||
Energy Corporation of America
|
7,402,983 (1) | 42.1 | % |
(1) | Includes 3,001,733 Common Units and 4,401,250 Subordinated Units. |
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THE TRUST
The trust is a statutory trust created under the Delaware Statutory Trust Act in March 2010.
The business and affairs of the trust is managed by The Bank of New York Mellon Trust Company,
N.A., as Trustee. Although ECA operates 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 acts as Delaware Trustee of the trust. The Delaware Trustee has 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 and its initial public offering, ECA conveyed to
a wholly owned subsidiary the Term PDP Royalty, which entitles the holder of the interest to
receive 45% of the proceeds from the sale of production of natural gas attributable to ECAs
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 and the Term PUD Royalty, which entitles such
holder of the interest to receive 25% of the proceeds from the sale of the production of natural
gas attributable to ECAs 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 in exchange for a demand
note in the principal amount of approximately $161 million.
In connection with the formation of the trust and its initial public offering, ECA and the
Private Investors conveyed to the trust the Perpetual PDP Royalty, which entitles 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) and ECA conveyed to the trust the Perpetual PUD Royalty, which entitles
the trust to receive an additional 25% of the proceeds from the sale of production of natural gas
attributable to ECAs interest in the PUD Wells (after deducting post-production costs and any
applicable taxes) in exchange for an aggregate 4,401,250 common units constituting 25% of the trust
units outstanding and 4,401,250 subordinated units constituting 25% of the trust units outstanding.
In connection with the formation of the trust and its initial public offering, ECAs
subsidiary conveyed the Term Royalties to the trust in exchange for the net proceeds from the
initial public offering, after deducting underwriting commissions and discounts and expenses, and
used the net proceeds to repay all or a portion of 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 Trustee may also hold funds awaiting
distribution in a non interest bearing account.
The trust is 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 is 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. For the year ended December 31,
2010, the trusts administrative expenses were approximately $1.0 million which includes fees
associated with the trust formation and initial public offering. The Trustees annual
administrative fee is $150,000 and may be adjusted beginning on the fifth anniversary of the trust
as provided in the trust agreement. The Delaware Trustees annual administrative fee is $2,400.
These costs as well as those to be paid to ECA pursuant to the Administrative Services Agreement
outlined below under Administrative services agreement and development agreement, are 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.
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ECA has a right of first refusal to purchase the Perpetual Royalties at the Termination Date.
This right of first refusal provides that the Trustee will use commercially reasonable efforts to
retain a third-party advisor to market the Perpetual Royalties within 30 business days of the
Termination Date. If the Trustee receives a bid from a proposed purchaser other than ECA and wants
to sell all or part of the Perpetual Royalties, it will be required to give notice (the Offer
Notice) to ECA, identifying the proposed purchaser and setting forth the proposed sale price,
payment terms and other material terms under which the Trustee is proposing to sell. ECA would then
have 30 days from receipt of the Offer Notice to elect, by notice to the Trustee, to purchase the
subject properties offered for sale on the terms and conditions set forth in the Offer Notice. If
ECA makes such election, the proposed purchaser would be entitled to receive reimbursement of its
reasonable and documented expenses incurred in connection with its review and analysis of the
subject properties and bid preparation. ECA and the trust would share equally the cost of
reimbursement to the proposed purchaser.
If ECA does not give notice within the 30-day period following the Offer Notice, the Trustee
may sell such properties to the identified purchaser on terms and conditions that are substantially
the same as those previously set forth in such Offer Notice.
If, after a reasonable marketing period, no bid is received on any or all of the Perpetual
Royalties from any party other than ECA, then ECA shall obtain, at the trusts expense, and deliver
to the Trustee, a fairness opinion from a nationally-recognized valuation firm with expertise in
fairness opinions stating that the proposed sale price to be paid by ECA to the trust for the
properties is fair to the trust.
ADMINISTRATIVE SERVICES AGREEMENT AND DEVELOPMENT AGREEMENT
In connection with the closing of the initial public offering on July 7, 2010, the trust
entered into an Administrative 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, totals $60,000. After the completion of ECAs drilling obligation,
subject to certain restrictions, ECA and the Trustee each may terminate the provisions of the
Administrative Services Agreement relating to the providing by ECA of administrative services at
any time following delivery of notice no less than 90 days prior to the date of termination.
The Development Agreement obligates ECA to drill all of the PUD Wells by March 31, 2013. In
the event of delays, ECA will have until March 31, 2014 under the Development Agreement to fulfill
its drilling obligation. ECA granted to the trust a lien on ECAs interest in the Marcellus Shale
formation in the AMI (except the Producing Wells and any other wells which were already producing
at the time of grant and not subject to the Royalties) in order to secure the estimated amount of
the drilling costs for the trusts interests in the PUD Wells
(the Drilling Support Lien). As of the grant date, the
amount obtained by the trust pursuant to the Drilling Support Lien
could not exceed $91 million. As
ECA fulfills its drilling obligation over time, the total dollar amount that may be recovered will
be proportionately reduced and the completed PUD Wells will be released from the lien. As of
December 31, 2010, the maximum amount of the Drilling Support Lien had been reduced to $74.1
million. However, after giving effect to the total number of wells drilled as of February 28, 2011
(26.83 wells, calculated as provided in the Development Agreement), the maximum amount of the
Drilling Support Lien would be reduced to approximately $44.0 million.
For purposes of ECAs drilling obligation, and subject to the following paragraph, 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 ECAs 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 ECAs 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 may be
required to drill more than the 52 Marcellus Shale natural gas development wells, in the aggregate,
if ECAs interest in any development well is less than 100%; provided, that ECA may be required to
drill fewer gross development wells due to lateral length of any well or wells exceeding 2,500
feet.
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
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beyond the mid-point of the curve, such well will not count as a fractional well. Wells with a
horizontal lateral distance of greater than 2,500 feet (subject to a maximum of 3,500 feet) will
count as one well plus a fractional well equal to the length drilled in excess of 2,500 (up to
3,500 feet) feet divided by 2,500 feet. Among the drilled wells, the average lateral length
completed has been approximately 3,700 feet, with some wells extending beyond the average with a
maximum lateral length drilled of 5,195 feet.
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
royalties Sale and abandonment of underlying properties.
ECA covenanted and agreed not to drill and complete, and will not permit any other person
within its control to drill and complete, any well in the Marcellus Shale formation on lease
acreage included within the AMI for its own account until such time as ECA has met its commitment
to drill the PUD Wells. Once ECA has completed its drilling obligation, the Trustee will be
required to release the Drilling Support Lien in full. Upon the Trustees 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 will have a
perforated segment that will be within 500 feet of any perforated interval of a PUD Well or
Producing Well in the Marcellus Shale formation.
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TARGET DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE THRESHOLDS
ECA created 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
entitles the trust to receive 90% of the proceeds (exclusive of any production or development costs
but after deducting post-production costs and any applicable taxes) from the sale of production of
natural gas attributable to ECAs interest in the Producing Wells for a period of 20 years
commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest entitles the trust to
receive 50% of the proceeds (exclusive of any production or development costs but after deducting
post-production costs and any applicable taxes) from the sale of future production of natural gas
attributable to ECAs interest in the PUD Wells for a period of 20 years commencing on April 1,
2010 and 25% thereafter.
The amount of trust revenues and cash distributions to trust unitholders will depend on:
| the timing of initial production from the PUD Wells; | ||
| natural gas prices received; | ||
| the volume and Btu rating of natural gas produced and sold; | ||
| post-production costs and any applicable taxes; | ||
| the reimbursement by the trust, if any, of ECAs costs associated with establishing the floor price contracts to be transferred to the trust; and | ||
| administrative expenses of the trust and expenses incurred as a result of being a publicly traded entity. |
ECA has calculated quarterly target levels of cash distributions for the life of the trust, such
levels having been set forth in the Initial Prospectus. The amount of the quarterly distributions may fluctuate from quarter to quarter, depending on
the proceeds received by the trust, among other factors.
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.
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 subordinated
4,401,250 of the trust units it retained following the formation of the trust and the initial
public offering, which constitutes 25% of the outstanding trust units. While the subordinated units
are 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. In
exchange for subordinating 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 is 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). ECAs right to receive the incentive distributions will terminate
upon the expiration of the subordination period.
ECA has incurred costs of approximately $5.0 million in establishing the floor price contracts
which were transferred to the trust at the closing of the trusts initial public offering. ECA is
entitled to reimbursement for these expenditures plus interest accrued at 10% per annum (the
Reimbursement Amount) only if and to the extent distributions to trust unitholders would
otherwise exceed the incentive threshold. This reimbursement is 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 automatically convert into common units on a one-for-one basis and
ECAs right to receive incentive distributions and to recoup the reimbursement amount will
terminate, at the end of the fourth full calendar quarter following ECAs satisfaction of its
drilling obligation to the trust. Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it has established for the benefit of the trust.
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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 under the Development
Agreement 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 through the first quarter of 2015.
Subordination | Target | Incentive | ||||||||||
Period | Threshold | Distribution(1) | Threshold | |||||||||
(per unit) | ||||||||||||
2011: |
||||||||||||
First Quarter |
$ | 0.446 | $ | 0.558 | $ | 0.669 | ||||||
Second Quarter |
0.451 | 0.564 | 0.676 | |||||||||
Third Quarter |
0.550 | 0.688 | 0.825 | |||||||||
Fourth Quarter |
0.565 | 0.706 | 0.847 | |||||||||
2012: |
||||||||||||
First Quarter |
0.574 | 0.717 | 0.861 | |||||||||
Second Quarter |
0.602 | 0.752 | 0.903 | |||||||||
Third Quarter |
0.624 | 0.780 | 0.937 | |||||||||
Fourth Quarter |
0.701 | 0.876 | 1.051 | |||||||||
2013: |
||||||||||||
First Quarter |
0.756 | 0.945 | 1.135 | |||||||||
Second Quarter |
0.754 | 0.942 | 1.131 | |||||||||
Third Quarter |
0.701 | 0.876 | 1.052 | |||||||||
Fourth Quarter |
0.659 | 0.824 | 0.989 | |||||||||
2014: |
||||||||||||
First Quarter |
0.610 | 0.763 | 0.915 | |||||||||
Second Quarter |
0.589 | 0.736 | 0.883 | |||||||||
Third Quarter |
0.571 | 0.713 | 0.856 | |||||||||
Fourth Quarter |
0.549 | 0.687 | 0.824 | |||||||||
2015: |
||||||||||||
First Quarter |
0.519 | 0.649 | 0.779 |
(1) | Target Distributions do not represent minimum quarterly distributions. There is no guarantee that the Trust will pay distributions at the target distribution level in any quarter. |
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THE ROYALTIES
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 Royalties were conveyed. ECA believes that
there are in excess of 100 potential drilling locations for the PUD Wells within the AMI. As of
December 31, 2010, the total gas reserves attributable to the
trust interests were 102.4 Bcf. This
amount includes 59.9 Bcf attributable to the proved undeveloped
reserves and 42.49 Bcf attributable
to the proved developed reserves. ECA is currently the operator of all of the wells subject to the
PDP Royalty Interest. ECA has an average working interest of approximately 93% in the wells subject
to the PDP Royalty Interest. Two third parties hold an approximate 50% and 35% working interest in
two Producing Wells. ECA holds the remaining approximate 50% and 65% working interest in such
wells. The reserves attributable to the Royalties 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
Royalties as well as the residual interest in the reserves that the trust will sell on or shortly
following the Termination Date.
SELECTED FINANCIAL DATA
The following table provides a summary of proceeds received by the Trust and distributable
income by quarter for 2010. ECA has not yet fulfilled its drilling obligation, and consequently
the information in the table set forth below will not be comparable to the trusts results going
forward as ECA completes additional wells. For more information please read our financial
statements included in this prospectus beginning on page F-1.
Quarter Ended | ||||||||||||||||||||
2010 | March 31 | June 30 | September 30 | December 31 | Total | |||||||||||||||
(all amounts in thousands except for distributable income per unit) | ||||||||||||||||||||
Net proceeds |
$ | | $ | 5,566 | $ | 7,918 | $ | 9,188 | $ | 22,672 | ||||||||||
Distributable income |
$ | | $ | 4,789 | $ | 7,419 | $ | 8,809 | $ | 21,017 | ||||||||||
Distributable income per unit |
$ | | $ | 0.272 | $ | 0.421 | $ | 0.500 | $ | 1.193 |
TRUSTEES DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
For the Three Months Ended December 31, 2010
The trusts distributable income was $8,809,013 for the three months ended December 31, 2010.
This amount was less than the projected cash available for distribution determined in establishing
the target distributions described in the Initial Prospectus by approximately $1.7 million.
Total revenues for the quarter of $9.2 million were $1.7 million less than the projected
amount of $10.9 million. This decrease in revenues was primarily the result of the $4.60 per Mcf
average price realized for the quarter being $0.92 per Mcf lower than the projected price of $5.52
per Mcf. This was partially offset by production volumes being greater than projected by 17 MMcf.
Twenty wells (14 Producing Wells and 6 PUD Wells) were online and producing at the end of the
quarter, which was two less than projected in the Initial Prospectus.
The average $4.60 per Mcf price realized for the quarter was lower than projected primarily as
a result of the weighted average closing NYMEX price of $3.81 per Dth being lower than the
projected price of $5.21 per Dth for the quarter. This lower weighted average NYMEX price was
partially offset as a result of the hedge proceeds received for the quarter being $1.2 million
greater than projected due to the lower NYMEX price.
Total production for the quarter of 1,996 MMcf was 17 MMcf higher than projected. Twenty wells
(14 Producing Wells and 6 PUD Wells) were online and producing at the end of the quarter, which was
two less than projected. Of the six PUD Wells, four of these wells were brought online during the
quarter ended December 31, 2010. One well was brought online in late October, two in mid November,
and one in late December. These four
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wells had an average daily production rate, net to the trust, of 3,924 Mcf per day for January
2011. The average gross initial per well production for the first thirty days of production for
these four wells was 3,159 Mcf per day which is 39.7% above the rate forecasted by the Ryder Scott
reserve report described in the Initial Prospectus for the same time period.
General and administrative expenses paid by the trust were $380,000 for the three months ended
December 31, 2010. This amount was $31,000 less than the projected expenses for the quarter,
primarily due to the timing of payment of invoices including the Trustee quarterly fee of $37,500
that was not paid until January 2011. During the three months ended December 31, 2010, ECA received
a quarterly Administrative Services Fee of $15,000.
From Inception to December 31, 2010
The Trusts distributable income was $21,016,633 from inception through December 31, 2010.
This amount was less than the projected cash available for distribution determined in establishing
the target distributions described in the Initial Prospectus by approximately $0.8 million.
Total revenues from inception through December 31, 2010 of $22.7 million were $0.4 million
less than the projected amount of $23.1 million. This decrease in revenues was primarily the result
of the $4.95 per Mcf average price realized for the period being $0.7574 per Mcf lower than the
projected price of $5.69 per Mcf. This was partially offset by production volumes being greater
than projected by 530 MMcf. Twenty wells (14 Producing Wells and 6 PUD Wells) were online and
producing at the end of the period, which was two less than projected.
The average $4.95 per Mcf price realized for the period was lower than projected primarily as
a result of the weighted average closing NYMEX price of $4.05 per Dth being lower than the
projected price of $4.91 per Dth for the period. This lower weighted average NYMEX price was
partially offset as a result of the hedge proceeds received being $1.6 million greater than
projected due to the lower NYMEX price.
Total production for the period of 4,583 MMcf was 530 MMcf higher than projected. Twenty wells
(14 Producing Wells and 6 PUD Wells) were online and producing at the end of the period, which was
two less than projected. Of the six PUD Wells, two were brought online in mid September, one was
brought online in late October, two in mid November, and one in late December. These six wells had
an average daily production rate, net to the trust, of 6,578 Mcf per day for January 2011. The
average gross initial per well production for the first thirty days of production for these six
wells was 2,854 Mcf per day which is 26.3% above the rate forecasted by the Ryder Scott reserve
report described in the Initial Prospectus for the same time period.
General and administrative expenses paid by the trust were $1.0 million for the period ended
December 31, 2010. This amount was $0.2 million less than the projected expenses. The Trustee
elected to waive its quarterly fee of $37,500 and ECA elected to waive its quarterly Administrative
Services Fee of $15,000 for the quarter ended June 30, 2010. Neither the Trustee nor ECA waived its
fees for the quarter ended September 30, 2010 or December 31, 2010 and neither intends to do so in
the future. Since inception, the Trustee has established a net cash reserve of $500,000 for use in
paying current and future liabilities of the trust as they become due. The Trustee currently
intends to maintain the reserve at this level, but may increase or decrease it at any time. This
cash reserve reduced the trusts distributable income for the period from inception to December 31,
2010.
Because the Trust reached the incentive distribution threshold amount to be paid on all trust
units for the quarters ended June 30, 2010, ECA received $58,688 (half of the amount in excess of
the threshold) as an incentive distribution, and an additional $58,688 (the other half of the
amount in excess of the threshold) as reimbursement for accrued interest on the floor contract
premiums, which are to be repaid to ECA during the subordination period when the incentive
distribution threshold amount is reached for all trust units in any quarter.
Recent Developments
ECA has drilled an additional fifteen PUD Wells as of February 28, 2011 and thirteen of these
wells are undergoing or awaiting completion operations while two were brought online in early
January 2011. As of February 28, 2011, ECA had drilled a total of twenty-one actual PUD Wells.
However, the average horizontal lateral distance for these twenty-one wells (as measured from the
midpoint of the curve to the end of the lateral) was 3,864 feet and
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represents a total of 26.83 net PUD Wells drilled, calculated as described in the Development
Agreement. These 26.83 net PUD Wells drilled count toward the 52 equivalent PUD Wells ECA has
committed to drill. The trust expects that ECA will complete its drilling obligation on or before March 31, 2013.
Liquidity and Capital Resources
The Trust has no source of liquidity or capital resources other than cash flows from the
Royalties. Other than trust administrative expenses, including any reserves established by the
Trustee for future liabilities, the trusts only use of cash is for distributions to trust
unitholders, including, if applicable, incentive distributions to ECA and, if applicable, expense
reimbursements to ECA. Administrative expenses include payments to the Trustee and the Delaware
Trustee as well as a quarterly fee of $15,000 to ECA pursuant to the Administrative Services
Agreement. Each quarter, the Trustee determines the amount of funds available for distribution.
Available funds are the excess cash, if any, received by the trust from the Royalties and other
sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the
trusts expenses for that quarter, subject in all cases to the subordination and incentive
provisions described above. Available funds are reduced by any cash the Trustee determines to hold
as a reserve against future expenses or liabilities. The Trustee may borrow funds required to pay
expenses or liabilities if the Trustee determines that the cash on hand and the cash to be received
are insufficient to cover the trusts expenses or liabilities. If the Trustee borrows funds, the
trust unitholders will not receive distributions until the borrowed funds are repaid.
Payments to the Trust in respect of the Royalties are based on the complex provisions of the
various conveyances held by the trust, copies of which are filed as exhibits to this registration
statement, and reference is hereby made to the text of the conveyances for the actual calculations
of amounts due to the trust.
The Trust does not have any transactions, arrangements or other relationships with
unconsolidated entities or persons that could materially affect the trusts liquidity or the
availability of capital resources.
NATURAL GAS RESERVES
Ryder Scott estimated natural gas reserves attributable to the Royalties as of December 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 the Royalties. The following table, effective as of December 31, 2010,
contains certain estimated proved reserves, estimated future net cash flows and the discounted
present value thereof attributable to the Royalties, 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 SECs 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 January
1, 2010 through December 31, 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 $4.65 per
Mcf. Proved reserve quantities attributable to the Royalties are calculated by multiplying the
gross reserves less fuel usage and line loss for each property by the royalty interest assigned to
the trust in each property. The net cash flows attributable to the trusts reserves are net of the
trusts obligation to reimburse ECA for the post-production costs. The reserves and cash flows
attributable to the trusts interests include only the reserves attributable to the Royalties that
are expected to be produced within the 20-year period in which the trust owns the royalty interest
as well as the 50% residual interest in the reserves that the trust will own on the Termination
Date. A summary of the reserve report is included as Annex A to this prospectus.
Proved Gas | Discounted | |||||||||||
Reserves | Estimated Future | Estimated Future | ||||||||||
Proved reserves | (Bcf) | Net Cash Flows | Net Cash Flows (1) | |||||||||
(Dollars in thousands) | ||||||||||||
Royalty Interests: |
||||||||||||
Proved Developed (2) |
42.486 | $ | 174,607 | $ | 98,757 | |||||||
Proved Undeveloped |
59.963 | 246,430 | 132,485 | |||||||||
Total |
102.449 | $ | 421,037 | $ | 231,242 | |||||||
(1) | The present values of future net cash flows for the Royalties were determined using a discount rate of 10% per annum. |
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(2) | Includes reserves currently behind pipe in wells which are in the process of being completed. |
Information concerning historical changes in net proved reserves attributable to the
Royalties, and the calculation of the standardized measure of discounted future net cash flows
related thereto, is contained in the unaudited supplemental information contained elsewhere in this
prospectus.
THE RESERVE REPORT
Technologies. The reserve report was prepared using decline curve analysis to determine the
reserves of individual Producing Wells. After estimating the reserves of each proved developed
well, it was determined that a reasonable level of certainty exists with respect to the reserves
which can be expected from any individual undeveloped well in the field. The consistency of
reserves attributable to the Producing Wells, which cover a wide area of the AMI, further supports
proved undeveloped classification.
Also, a 3-D seismic survey was shot and interpreted across substantially all of the AMI and
has been used to confirm the consistency of important reservoir properties throughout the AMI.
Seismic interpretation has been used to support ECAs belief of a consistency of Marcellus Shale
formation thickness across the AMI, which is further substantiated by electric log and mudlog data
from wells drilled on the Underlying Properties and adjacent wells drilled by third-party
operators. Also, ECA has recently begun using seismic analysis of structural features on the
Underlying Properties to optimally place PUD Wells within the acreage. By observing faults and
other structural features within the acreage, ECA is able to place PUD Wells so that they will have
the longest lateral length possible while staying in the Marcellus Shale formation by avoiding
significant faults. The location of these faults also confirms the number of potential proved
undeveloped locations on the acreage and indicates that the PUD locations will be able to be
drilled without crossing significant faults or encountering structural features, such as steeply
dipping beds near faults, which could limit lateral length. Electric logs and other geologic and
engineering data gathered from proved developed wells and vertical Marcellus Shale wells ECA has
previously drilled across the AMI further support the consistency of the Marcellus Shale reservoir
throughout the AMI. Finally, ECA regularly trades geologic, engineering, and operations data with
other operators in the area surrounding the AMI. This technical and production data further
supports the consistency of the Marcellus Shale in and around the AMI.
While a number of PUD Wells within the Underlying Properties are not direct offsets of other
producing wells, both ECA and Ryder Scott, as independent petroleum engineers, were reasonably
certain that all of the undrilled wells could be classified as PUD Wells because of the consistency
of the Marcellus Shale formation across the AMI. As noted above, 3-D seismic data has been used to
target PUD Well placement so as to avoid encountering significant faults or structural features.
Data from both ECA and offset operators with which ECA has exchanged technical data demonstrate a
consistency in this resource play over an area much larger than the AMI. In addition, direct
measurement from other producing wells has also been used to confirm consistency in reservoir
properties such as total organic content, vitrinite reflectance, porosity, thickness, and
stratigraphic conformity. Most importantly, production from other producing wells confirms that
horizontal Marcellus Shale wells across the AMI have similar performance with respect to initial
production, decline curve shape, and estimated ultimate recovery.
Internal Controls. Ryder Scott prepared its report as described above in accordance with
appropriate engineering, geologic, and evaluation principles and techniques that are in accordance
with practices generally accepted in the petroleum industry, and definitions and guidelines
established by the SEC. These reserves, estimation methods and techniques are widely taught in
university petroleum curricula and throughout the industrys ongoing training programs. Although
these appropriate engineering, geologic, and evaluation principles and techniques that are in
accordance with practices generally accepted in the petroleum industry are based upon established
scientific concepts, the application of such principles involves extensive judgment and is subject
to changes in existing knowledge and technology, economic conditions and applicable statutory and
regulatory provisions. The same industry wide applied techniques are used in determining estimated
reserve quantities. The technical persons responsible for preparing the reserve estimates
presented herein meet the requirements regarding qualifications, independence, objectivity and
confidentiality set forth in the Society of Petroleum Engineering Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information. ECA has advised the Trust that it
maintains adequate controls over the underlying data it provides to Ryder Scott, which is designed
to result in accurate and reliable data in compliance with applicable regulations and guidance.
The data ECA furnishes to Ryder Scott is reviewed by staff reservoir engineers and geoscientists
before review by the Senior Reservoir Engineer and finally the Vice President of Eastern
Operations. These individuals consult regularly with Ryder Scott
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during Ryder Scotts reserve estimation process to review properties, assumptions, and any new
data available. ECAs Senior Reservoir Engineer has a Bachelor of Science in Petroleum Engineering.
He has over 3 years of oil and gas industry experience in reservoir Engineering. ECAs Vice
President of Eastern Operations is the primary technical person responsible for overseeing the data
reporting process. This individual has a Bachelor of Science degree in Chemical Engineering with
Masters of Petroleum Engineering coursework along with a Master of Business Administration degree.
He has worked in drilling, completions, production, and reservoir engineering along with
acquisitions during his career and is a member of the Society of Petroleum Engineers.
Material Changes. Since the March 31, 2010 reserve report, ECA completed the six Producing Wells
which were in the process of being completed and were noted in the March 31, 2010 reserves as
currently behind pipe in existing wells. Also during this time, ECA drilled and completed the
first six PUD wells, which have since been classified as proved developed. Finally, ECA drilled two
additional PUD Wells which were included in proved developed reserves as of December 31, 2010, and
were completed but awaiting initial production.
Well Locations
ECA has over 100 locations within the AMI and may drill some of the PUD Wells on units that
encompass land controlled by third-party operators in order to maximize recovery in the field and
also maximize the lateral length of each PUD Well drilled. If ECA drills one or more PUD Wells in
which it controls less than 100% working interest, it will be obligated to drill additional PUD
Wells above the 52 planned for the trust in order to make the total number of net (equivalent) PUD
Wells equal 52, provided that ECA may be required to drill fewer gross development wells due to
lateral length from any well or wells exceeding 2,500 feet. For instance, if ECA drilled one well
in which it controlled 50% working interest, and it was drilled to a horizontal lateral length of
2,500 feet, this well would only count as one-half of a PUD Well. In order to compensate for this,
ECA would be obligated to drill an additional PUD Well with a horizontal lateral length of 2,500
feet and a 50% working interest so that the trust still received in total 52 equivalent wells.
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 Royalties, 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 Royalties. 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.
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MARKETING AND POST-PRODUCTION SERVICES
Pursuant
to the terms of the conveyances creating the Royalties, ECA has the
responsibility to market, or cause to be marketed, the natural gas production related to the
Royalties. The terms of the conveyances creating the Royalties 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 attributable to the Royalties
will be determined based on the same price (net of post-production costs) that ECA receives for
natural gas production attributable to ECAs retained interest.
A wholly owned subsidiary of ECA markets the majority of ECAs operated production and markets
substantially all of the gas produced attributable to the Royalties. 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. Currently the primary aggregators of supply with whom ECA
currently does business in the AMI are BP Energy Company, Centerpoint Energy Services, Inc., South
Jersey Resource Group and Hess Corporation. In addition to providing marketing services, ECAs
subsidiary purchases all of the production from the Underlying
Properties and those sales account for 100% of
the revenue attributable to the Royalties.
Substantially all of the production from the Producing Wells and the PUD Wells is or will be
gathered by ECAs Greene County Gathering System. The Trust pays the initial Post-Production
Services Fee of $0.52 per MMBtu for use of this system, including ECAs costs to gather, compress,
transport, process, treat, dehydrate and market the gas. This fee is fixed until ECAs 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 December 31, 2010 reserve
report described elsewhere in this registration statement 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 trusts cash available for
distribution will be reduced by ECAs deductions for these post-production services.
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 Trusts 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, 2010. However, 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 attributable to the Royalties marketable, so long as such costs do not materially
exceed the charges prevailing in the area for similar services.
ECA recently executed a binding precedent agreement with a third party to provide firm
transportation downstream of ECAs Greene County Gathering System for 50,000 Dth per day. This firm
transportation arrangement is scheduled to be in service August 1, 2011 and will be at the third
partys filed tariff rate, which equates to $0.1996 per MMbtu at one hundred percent loadfactor.
This is a post-production cost which will ensure downstream capacity and such costs will be charged
to the trusts interest.
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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 attributable to the Royalties.
TITLE TO PROPERTIES
The Underyling Properties are subject to certain burdens that are described in more detail
below. To the extent that these burdens and obligations affect ECAs rights to production and the
value of production from the Underlying Properties, they have been taken into account in
calculating the trusts interests and in estimating the size and the value of the reserves
attributable to the Royalties.
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.
ECAs interests in the gas properties comprising the Underlying Properties are typically
subject, in one degree or another, to one or more of the following:
| royalties and other burdens, express and implied, under gas leases; | ||
| production payments and similar interests and other burdens created by ECA or its predecessors in title; | ||
| a variety of contractual obligations arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; | ||
| liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings; | ||
| pooling, unitization and communitization agreements, declarations and orders; | ||
| easements, restrictions, rights-of-way and other matters that commonly affect property; | ||
| conventional rights of reassignment that obligate ECA to reassign all or part of a property to a third party if ECA intends to release or abandon such property; and | ||
| rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and the royalty interests therein. |
ECA believes that the burdens and obligations affecting the Underlying Properties 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 Royalties.
ECA believes that its title to the Underlying Properties, and the trusts title to the
Royalties, is 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 Royalties. Consistent with industry practice, ECA has not
obtained preliminary title reviews of the PUD Wells that have not
been drilled. Prior to drilling each new 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 other
than the preliminary title review conducted prior to the drilling of a PUD Well. The conveyances
related to the PUD Royalty Interest obligate 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.
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It is unclear under Pennsylvania law whether the Royalties would be treated as real property
interests. Nevertheless, ECA has recorded the conveyances of the Royalties in the real property
records of Pennsylvania in accordance with local recording acts. ECA has granted 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 Royalties 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 they may need to sell natural gas
regardless of price to attempt to maintain cash flow. The Trust is subject to the same competitive
conditions as ECA and other companies in the natural gas industry.
Natural gas competes with other forms of energy available to customers, primarily based on
price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy, as well as business conditions,
conservation, legislation, regulations and the ability to convert to alternate fuels and other
forms of energy may affect the demand for natural gas.
Future price fluctuations for natural gas will directly affect trust distributions, estimates
of reserves attributable to the trusts interests, and estimated and actual future net revenues to
the trust. In view of the many uncertainties that affect the supply and demand for natural gas,
neither the Trust nor ECA can make reliable predictions of future gas supply or demand, future gas
prices or the effect of future gas prices on the trust.
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 Commissions 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 ECAs 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 ECAs
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 ECAs 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 ECAs operations, and there can be no assurance that ECA will not incur significant
costs
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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 ECAs business operations are subject and for which compliance may
have a material adverse impact on ECAs 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 ECAs 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, petroleum
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 petroleum 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 petroleum hydrocarbons and wastes was
not under ECAs 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 Earths atmosphere and other climatic changes, the
EPA determined in December 2009 that emissions of GHGs present an endangerment to public health and
the environment. Based on these findings, the EPA has begun adopting and implementing regulations
to restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA
recently adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which
requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates
emissions of GHGs from certain large stationary sources under the Prevention of Significant
Deterioration
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(PSD) and Title V permitting programs, effective January 2, 2011. This stationary source
rule tailors these permitting programs to apply to certain stationary sources in a multi-step
process, with the largest sources first subject to permitting. Facilities required to obtain PSD
permits for their GHG emissions also will be required to reduce those emissions according to best
available control technology standards for GHG that will be established by the states or, in some
instances, by the EPA on a case-by-case basis. The EPAs rules relating to emissions of GHGs from
large stationary sources of emissions are currently subject to a number of legal challenges, but
the federal courts have thus far declined to issue any injunctions to prevent EPA from
implementing, or requiring state environmental agencies to implement, the rules. In addition, in
November 2010, the EPA expanded its existing GHG reporting rule to include onshore oil and natural
gas production, processing, transmission, storage, and distribution facilities, beginning in 2012
for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation
to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to
reduce emissions of GHGs primarily through the planned development of GHG emission inventories
and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring
major sources of emissions, such as electric power plants, or major producers of fuels, such as
refineries and gas processing plants, to acquire and surrender emission allowances. The number of
allowances available for purchase is reduced each year in an effort to achieve the overall GHG
emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require
ECA to incur increased operating costs, such as costs to purchase and operate emissions control
systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.
Any such legislation or regulatory programs could also increase the cost of consuming, and thereby
reduce demand for, the oil and natural gas ECA produces. Consequently, legislation and regulatory
programs to reduce emissions of GHGs could have an adverse effect on ECAs business, financial
condition and results of operations. Finally, it should be noted that some scientists have
concluded that increasing concentrations of GHGs in the Earths 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 ECAs 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. The process is typically regulated by
state oil and gas commissions. However, the EPA recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, with results of the study expected to be
available in late 2012, and a committee of the U.S. House of Representatives is also conducting an
investigation of hydraulic fracturing practices. In addition, legislation was introduced in the
recently completed 111th Session of Congress to provide for federal regulation of
hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, and
such legislation could be introduced and adopted in the current session of Congress. Also, some
states have adopted, including Pennsylvania, and other states are considering adopting, regulations
that could impose more stringent permitting, disclosure and well construction requirements on
hydraulic fracturing operations. If new laws or regulations that
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significantly restrict hydraulic fracturing are adopted, such laws could make it more
difficult or costly for ECA to perform fracturing to stimulate production from tight formations.
In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal
legislation or regulatory initiatives by the EPA, ECAs fracturing activities could become subject
to additional permitting requirements, and also to attendant permitting delays and potential
increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and
natural gas that ECA is ultimately able to produce.
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 ECAs
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 ECAs 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 ECAs wells and to limit the number of wells or locations ECA can drill.
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DESCRIPTION OF THE ROYALTIES
The Royalties
were conveyed to the Trust by ECA by means of conveyance instruments that have
been recorded in the appropriate real property records in Greene
County, Pennsylvania where the Underlying Properties to which the Royalties relate are located. The PDP Royalty Interest burdens 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 burdens 50% of all of the interests of ECA in the
Marcellus Shale formation in the AMI. ECAs interests in the Underlying Properties to which the PUD Wells
relate consist of an average working interest of 100%. The conveyances related to the PUD Royalty
Interest, however, provide 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 ECAs 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 ECAs
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).
Generally, the percentage of
production proceeds to be received by the Trust with respect to a
well will equal the product of (i) the percentage of proceeds to which the trust is entitled under
the terms of the conveyances (90% for the Producing Wells and 50% for the PUD Wells) multiplied by
(ii) ECAs net revenue interest in the well. ECA on average owns an 81.53% net revenue interest in
the Producing Wells. Therefore, the trust is entitled to receive on average 73.37% of the proceeds
of production from the Producing Wells. With respect to a PUD Well, the conveyances related to the
PUD Royalty Interest provide that the proceeds from the PUD Wells will be calculated on the basis
that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5%
of the revenues from such properties, regardless of whether the royalty interest owners are
actually entitled to a greater percentage of revenues from such properties. As the applicable net
revenue interest of a well is calculated by multiplying ECAs percentage working interest in such
well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a
PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the trust would
be entitled to 43.75% of the production proceeds from such well.
Pursuant to the Development Agreement, ECA will satisfy its drilling obligation only when it
has drilled 52 equivalent wells. The proved undeveloped reserves included in the reserve report
represent the reserves assigned to undeveloped locations that ECA anticipates drilling. However,
under the conveyances, ECA is obligated to act as a reasonably prudent operator in the AMI under
the same or similar circumstances as it would if it were acting with respect to its own properties,
disregarding the existence of the royalty interests as burdens affecting such properties.
Accordingly, there may be situations where ECA will be obligated to drill on one or more of the
over 100 potential drilling locations within the AMI, including the 52 drilling locations
identified in the reserve report, that are not those identified locations underlying the reserve
report.
Based on extensive geologic and engineering data from the Producing Wells and vertical
Marcellus Shale wells in the AMI, as well as 3-D seismic testing within the region, ECA believes
that the Marcellus Shale formation has demonstrated consistency in formation thickness and other
important characteristics across the AMI. When combined with the fact that ECA is obligated to
operate as a reasonably prudent operator with respect to the PUD Wells, ECA believes that a
deviation from the 52 identified drilling locations underlying the reserve report would not occur
absent a reasonable belief that (i) such deviation would not result in production at least equal to
that of the location deviated from, and (ii) not materially reduce the anticipated reserves
attributable to the 52 equivalent wells forming the PUD Wells. To the extent ECAs working interest
in a PUD Well is less than 100%, the trusts share of proceeds would be proportionately reduced.
Pursuant to the Development Agreement, however, ECA will only satisfy its drilling obligation when
it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds attributable to
a PUD Well caused by ECA having less than a 100% working interest in the well will be offset by the
requirement to drill additional wells. An equivalent PUD Well is calculated by multiplying the
working interest held by ECA by the horizontal lateral length of the well relative to 2,500 feet.
PUD Wells drilled horizontally in the Marcellus Shale formation with a horizontal lateral distance
(measured from the midpoint of the curve to the end of the lateral) of less than 2,500 feet will
count as a fractional well in proportion to total lateral length divided by 2,500 feet. In the
event ECA commences drilling of a PUD Well but fails to drill beyond the mid-point of the curve,
such well will not count as a fractional well. PUD 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. Accordingly, for example, if ECA
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drilled one well in which it has a 50% working interest, and such well was drilled to a
horizontal lateral length of 2,500 feet, such well would count for purposes of the Development
Agreement as only 0.50 PUD Wells. In order to compensate for this, ECA would be obligated to drill
an additional 0.50 PUD Wells. Such additional 0.50 PUD Wells could be achieved, for example, by
drilling an additional PUD Well with a horizontal lateral length of 3,000 feet (or 500 feet longer
than the 2,500 foot base lateral length) in which ECA holds a 41.7% working interest, or by
drilling an additional PUD Well with a horizontal lateral length of 2,000 feet (or 500 feet shorter
than the 2,500 foot base lateral length) in which ECA holds a 62.5% working interest. ECA believes
that longer laterals will produce more reserves both in the near term and ultimately. Consequently,
longer lateral distances achieved should provide incremental benefit to the trust. The maximum
credit ECA can earn toward the 52 well requirement under the Development Agreement by drilling a
single actual well is 1.4 wells, calculated as described above.
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 (exclusive of any
production or development costs but after deducting post-production costs and any applicable taxes)
from the sale of estimated natural gas production attributable to the Producing Wells regardless of
whether such amounts have actually been received by ECA from the purchases of the natural gas
produced. Proceeds from the sale of natural gas production attributable to the Producing Wells in
any calendar quarter means:
| amount calculated based on estimated production volumes attributable to the Producing Wells; |
in each case, after deducting the Trusts proportionate share of:
| any taxes levied on the severance or production of the natural gas produced from the Producing Wells and any property taxes attributable to the natural gas production attributable to the Producing Wells; and | ||
| post-production costs, which generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production costs on its Greene County Gathering System will be limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Service Fee to the extent it is necessary to recover certain capital expenditures in ECAs Greene County Gathering System. Additionally, the trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used. |
Proceeds payable to the Trust from the sale of natural gas production attributable to the
Producing Wells in any calendar quarter are not 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 entitle the Trust to
receive an amount of cash for each calendar quarter equal to 50% of the proceeds (after deducting
post-production costs and any applicable taxes) from the sale of estimated natural gas production
attributable to the PUD Wells regardless of whether such amounts have actually been received by ECA
from the purchase of the natural gas produced. Proceeds from the sale of natural gas production, if
any, attributable to the PUD Wells in any calendar quarter means:
| for any calendar quarter commencing on or after April 1, 2010, the amount calculated based on estimated production volumes attributable to the PUD Wells: |
in each
case after deducting the Trusts proportionate share of:
| any taxes levied on the severance or production of the natural gas produced from the PUD Wells and any property taxes attributable to the gas produced from the PUD Wells; and | ||
| post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Any charge payable to ECA for such post-production charges on its with ECAs Greene County Gathering System is limited to $0.52 per MMBtu of gas gathered until ECA has fulfilled its drilling obligation. Thereafter, ECA may increase this Post-Production Services Fee to the extent is necessary to recover certain capital expenditures in ECAs Greene County Gathering |
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System. Additionally, the Trust is charged for the cost of fuel used in the compression process, including equivalent electricity charges in instances when electric compressors are used. |
Proceeds, if any, payable to the Trust from the sale of natural gas production attributable to
the PUD Wells in any calendar quarter:
| will be determined on the basis that ECAs working interest with respect to the PUD Wells is not subject to burdens (landowners royalties and other similar interests) in excess of 12.5% of the proceeds from gas production attributable to ECAs interest; and | ||
| will not be subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of natural gas production attributable to the underlying PUD properties, including any costs to plug and abandon a well included in the underlying PUD properties. |
Royalty Interest Lien
Under the laws of Pennsylvania, it is not clear that the Royalties conveyed by ECA to the
Trust would be treated as real property interests. Therefore, ECA has granted 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 Royalties were not considered real property interests. More
specifically, the Royalty Interest Lien is 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 ECAs 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 Royalties.
The Royalty Interest Lien does not include ECAs retained interest in the PUD and Producing
Wells and the AMI or other interest of ECA in the AMI, and ECA has the right to lien, mortgage,
sell or otherwise encumber the ECA retained interest subject to the Royalty Interest Lien.
ECA has recorded the conveyances of the Royalties and a Mortgage/Fixture Filing in the real
estate records of Greene County, Pennsylvania and has filed a corresponding UCC-1 Financing
Statement in the Office of the Secretary of State of West Virginia and the Commonwealth of
Pennsylvania.
The conveyances also provide that if ECAs interest with respect to the PDP properties is
greater than what was warranted to the trust in the conveyances, ECA will have the right to offset
against amounts owed to the trust, the difference between what the trust actually receives from PDP
Royalty Interest and what the trust should have received from the PDP Royalty Interest had ECAs
interest been the amount warranted.
Hedging Contracts Transferred to the Trust
The primary asset of and source of income to the trust are the Royalties, which generally
entitle the trust to receive varying portions of the net proceeds from gas production from the
Underlying Properties. Consequently, the trust is exposed to market risk from fluctuations in gas
prices. Through March 31, 2014, however, the Royalties are
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subject to the hedge contracts described below, which are expected to reduce the trusts
exposure to natural gas price volatility.
The hedge contracts consist of natural gas derivative floor price contracts and a back-to-back
swap agreement ECA entered into with the Trust to provide the trust with the benefit of certain
contracts previously entered into between ECA and third parties that equate to approximately 50% of
the estimated natural gas to be produced by the trust properties through March 31, 2014. The swap
contracts relate to approximately 7,500 MMBtu per day at a weighted average price of $6.78 per
MMBtu for the period commencing as of April 1, 2010 through June 30, 2012. The price of the floor
price hedging contracts is $5.00 per MMBtu.
The following table sets forth the volumes of natural gas covered by the natural gas hedging
contracts and the floor price for each quarter during the term of the contracts.
Swap Volume | Swap Price | Floor Volume | Floor Price | |||||||||||||
(MMBtu) | (MMBtu) | (MMBtu) | (MMBtu) | |||||||||||||
2010 |
||||||||||||||||
Second Quarter |
682,500 | $ | 6.75 | | | |||||||||||
Third Quarter |
690,000 | $ | 6.75 | | | |||||||||||
Fourth Quarter |
690,000 | $ | 6.75 | 225,000 | $ | 5.00 | ||||||||||
2011 |
||||||||||||||||
First Quarter |
675,000 | $ | 6.75 | 159,000 | $ | 5.00 | ||||||||||
Second Quarter |
682,500 | $ | 6.75 | 210,000 | $ | 5.00 | ||||||||||
Third Quarter |
690,000 | $ | 6.82 | 405,000 | $ | 5.00 | ||||||||||
Fourth Quarter |
690,000 | $ | 6.82 | 384,000 | $ | 5.00 | ||||||||||
2012 |
||||||||||||||||
First Quarter |
682,500 | $ | 6.82 | 369,000 | $ | 5.00 | ||||||||||
Second Quarter |
682,500 | $ | 6.82 | 516,000 | $ | 5.00 | ||||||||||
Third Quarter |
1,305,000 | $ | 5.00 | |||||||||||||
Fourth Quarter |
1,362,000 | $ | 5.00 | |||||||||||||
2013 |
||||||||||||||||
First Quarter |
1,395,000 | $ | 5.00 | |||||||||||||
Second Quarter |
1,380,000 | $ | 5.00 | |||||||||||||
Third Quarter |
1,278,000 | $ | 5.00 | |||||||||||||
Fourth Quarter |
1,188,000 | $ | 5.00 | |||||||||||||
2014 |
||||||||||||||||
First Quarter |
1,092,000 | $ | 5.00 |
The Trusts counterparties under the natural gas floor price contracts are Wells Fargo
Foothill, Inc. and BP Energy Company, and its counterparty under the back-to-back swap agreement is
ECA, whose counterparties are also Wells Fargo Foothill, Inc. and BP Energy Company. In the event
that any of the counterparties to the natural gas hedging contracts default on their obligations to
make payments to the trust, the cash distributions to the trust unitholders would likely be
materially reduced as the hedge payments are intended to provide additional cash to the Trust
during periods of lower natural gas prices. ECA will have no continuing obligation with respect to
the natural gas floor price contracts. However, ECA will be the Trusts counterparty under the
back-to-back swap agreement and will have continuing obligations with respect to this agreement.
ADDITIONAL PROVISIONS
If a controversy arises as to the sales price of any production, then for purposes of
determining gross proceeds:
| amounts withheld or placed in escrow by a purchaser are not considered to be received by the owner of the underlying property until actually collected; | ||
| amounts received by the owner of the underlying property and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and | ||
| amounts received by the owner of the underlying property and not deposited with an escrow agent will be considered to have been received. |
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The Trustee is not obligated to return any cash received from the Royalties. However, any
overpayments made to the trust by ECA due to adjustments to prior calculations of proceeds or
otherwise will reduce future amounts payable to the trust until ECA recovers the overpayments.
The conveyances generally permit ECA to sell, without the consent or approval of the trust
unitholders, all or any part of its interest in the Underlying Properties, if the Underlying
Properties are sold, subject to and burdened by the Royalties. Notwithstanding the foregoing, the
conveyances provide that ECA may not sell any of the Underlying Properties subject to the PUD
Royalty Interest until it has satisfied its obligation to drill PUD Wells pursuant to the terms of
the Development Agreement. The trust unitholders are not entitled to any proceeds of any sale of
ECAs interest in the Underlying Properties that remains subject to and burdened by the Royalties.
Following any such sale, the proceeds attributable to the transferred property will be calculated
pursuant to the conveyances as described in this registration statement, and paid by the purchaser
or transferee to the Trust.
Subject to the terms of the conveyances, ECA may at its option at any time prior to the
completion of its drilling obligation, cause the trust to exchange leased acreage subject to the
Royalties, free and clear of such Royalties, for other leased acreage within the AMI (as defined in
the conveyances). Such leased acreage exchanged to the trust shall then be subject to the Royalties
as set forth in the conveyances.
Additionally, the conveyances provide that, in the event ECA acquires any additional leases in
the AMI prior to the completion of its drilling obligation, ECA may at its option make such
additional lease subject to the Royalties. In no event may any additional lease become subject to
the Royalties, or any exchange of acreage be effected, unless ECA certifies to the trust that,
among other things, all of the aggregate acreage attributable to the additional leases and exchange
leases shall not exceed five percent of the acreage subject to the Royalties.
ECA or any transferee of an Underlying Property will have the right to abandon any well or
property if it reasonably believes the well or property ceases to produce or is not capable of
producing in commercially paying quantities. In making such decisions, ECA or any transferee of an
Underlying Property is required under the applicable conveyance to act as a reasonably prudent
operator in the AMI under the same or similar circumstances would act if it were acting with
respect to its own properties, disregarding the existence of the royalty interests as burdens
affecting such property. Upon termination of the lease, that portion of the royalty interests
relating to the abandoned property will be extinguished.
ECA may, without the consent of the trust unitholders, require the trust to release royalty
interests with an aggregate value to the trust up to $5.0 million during any twelve 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.
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.
ECA must maintain books and records sufficient to determine the amounts payable for the
Royalties to the Trust. Quarterly and annually, ECA must deliver to the Trustee a statement of the
computation of the proceeds for each computation period as well as quarterly drilling and
production results. ECA is not a publicly held company, and although ECA has continuing obligations
to the Trust, ECA has no obligation to publicly file any reports with the SEC.
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DESCRIPTION OF THE TRUST AGREEMENT
The Trust was created under Delaware law to acquire and hold the Royalties for the benefit of
the trust unitholders pursuant to an agreement between ECA, the Trustee and the Delaware Trustee.
The Royalties are passive in nature and neither the Trust nor the Trustee has any control over or
responsibility for costs relating to the operation of the Royalties. Neither ECA nor other
operators of the Royalties have any contractual commitments to the trust to provide additional
funding or to conduct further drilling on or to maintain their ownership interest in any of these
properties other than the obligations of ECA to designate and drill PUD Wells.
The trust agreement provides that the trusts business activities are limited to owning the
Royalties and any activity reasonably related to such ownership, including activities required or
permitted by the terms of the conveyances related to the Royalties and the natural gas hedging
contracts relating to an estimated 50% of the Trusts royalty production for a term ending March
31, 2014. As a result, the Trust is not permitted to acquire other oil and gas properties or
royalty interests.
The beneficial interest in the trust is divided into 17,605,000 trust units. The number of
trust units is fixed and the Trust is not permitted to issue additional trust units. Each of the
trust units represents an equal undivided beneficial interest in the assets of the trust; subject,
however, to the provisions relating to the subordinated units. Please read Description of the
trust units for additional information concerning
the trust units.
Amendment of the trust agreement generally requires a vote of holders of a majority of the
outstanding trust units, except that amendments that would result in a materially disproportionate
benefit to ECA or its affiliates compared to other owners of common units require a vote of the
holders of a majority of the outstanding common units and a majority of the outstanding trust
units. However, no amendment may:
| increase the power of the Trustee to engage in business or investment activities; | ||
| alter the rights of the trust unitholders as among themselves; or | ||
| permit the Trustee to distribute the royalty interests in kind. |
Certain amendments to the trust agreement do not require the vote of the trust unitholders.
The Trustee may, without approval of the trust unitholders, from time to time supplement or amend
the trust agreement in order to cure any ambiguity or to correct or supplement any defective or
inconsistent provisions provided such supplement or amendment is not adverse to the interest of the
trust unitholders. The business and affairs of the trust are managed by the Trustee. Although ECA
operates all of the Producing Wells and substantially all of the PUD Wells during the subordination
period, ECA has no ability to manage or influence the management of the trust.
ASSETS OF THE TRUST
The assets of the Trust consist of the Royalties, natural gas hedging contracts, the
Administrative Services Agreement, the Development Agreement, and any cash and temporary
investments being held for the payment of expenses and liabilities and for distribution to the
trust unitholders.
DUTIES AND POWERS OF THE TRUSTEE
The duties of the Trustee are specified in the trust agreement and by the laws of the State of
Delaware, except as modified by the trust agreement. The Trustees principal duties consist of:
| collecting cash attributable to the royalty interests; | ||
| paying expenses, charges and obligations of the trust from the trusts assets; | ||
| determining whether cash distributions exceed subordination or incentive thresholds, and making such cash distributions to the common and subordinated unitholders and ECA with respect to its right to receive incentive distributions and reimbursement of its approximately $5.0 million hedging costs; |
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| causing to be prepared and distributed a Schedule K-1 for each trust unitholder and to prepare and file tax returns on behalf of the Trust; and | ||
| causing to be prepared and filed reports required to be filed under the Securities Exchange Act of 1934, as amended, and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading. |
If a Trust liability is contingent or uncertain in amount or not yet currently due and
payable, the Trustee may create a cash reserve to pay for the liability. If the Trustee determines
that the cash on hand and the cash to be received are insufficient to cover the trusts liability,
the Trustee may borrow funds required to pay the liabilities. The Trustee may borrow the funds from
any person, including itself or its affiliates. The terms of such indebtedness, if funds were
loaned by the entity serving as Trustee or Delaware Trustee, would be similar to the terms which
such entity would grant to a similarly situated commercial customer with whom it did not have a
fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any
such indebtedness as if it were not then serving as Trustee or Delaware Trustee. If the Trustee
borrows funds, the trust unitholders will not receive distributions until the borrowed funds are
repaid.
Each quarter, the Trustee pays trust obligations and expenses and distribute to the trust
unitholders the remaining proceeds received from the royalty interests. The cash held by the
Trustee as a reserve against future liabilities must be invested in:
| interest bearing obligations of the United States government; | ||
| money market funds that invest only in United States government securities; | ||
| repurchase agreements secured by interest-bearing obligations of the United States government; | ||
| bank certificates of deposit; or | ||
| cash held for distribution at the next distribution date may be held in a non interest bearing account. |
The Trust may not acquire any asset except the Royalties, the natural gas hedging contracts,
cash and temporary cash investments, and it may not engage in any investment activity except
investing cash on hand.
The Trust may merge or consolidate with or into one or more limited partnerships, general
partnerships, corporations, business trusts, limited liability companies, or associations or
unincorporated businesses if such transaction is agreed to by the Trustee and by the affirmative
vote of the holders of a majority of the outstanding trust units (or by the holders of a majority
of the common units and a majority of the outstanding trust units if such transaction would result
in a materially disproportionate benefit to ECA or its affiliates compared to other owners of
common units) and such transaction is permitted under the Delaware Statutory Trust Act and any
other applicable law.
The Trustee may sell the Royalties under any of the following circumstances:
| the sale is requested by ECA, following the satisfaction of its drilling obligation, in accordance with the provisions of the trust agreement; or | ||
| the holders representing a majority of the outstanding trust units approving the sale (or by the holders of a majority of the common units and a majority of the outstanding trust units if such transaction would result in a materially disproportionate benefit to ECA or its affiliates compared to other owners of common units). |
Upon dissolution of the Trust the Trustee must sell the Royalties. No trust unitholder
approval is required in this event.
The Trustee distributes the net proceeds from any sale of the Royalties and other assets to
the trust unitholders.
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The Trustee may amend or supplement the trust agreement, the conveyances, the Development
Agreement, the Administrative Services Agreement, the hedge agreements, the registration rights
agreement, the Drilling Support Lien and the Royalty Interest Lien, without the approval of the
trust unitholders, to cure ambiguities, to correct or supplement defective or inconsistent
provisions, to grant any benefit to all trust unitholders, to add collateral to the Drilling
Support Lien and the Royalty Interest Lien or to change the name of the trust, provided, however,
that any such supplement or amendment does not adversely affect the interest of the trust
unitholders. Furthermore, the Trustee, acting alone, may amend the Administrative Services
Agreement without the approval of trust unitholders if such amendment would not increase the cost
or expense of the trust or create an adverse economic impact on the trust unitholders. All other
permitted amendments may only be made by the affirmative vote of a majority of the trust units (or
by the holders of a majority of the common units and a majority of the outstanding trust units if
such transaction would result in a materially disproportionate benefit to ECA or its affiliates
compared to other owners of common units).
LIABILITIES OF THE TRUST
Because the trust does not conduct an active business and the Trustee has little power to
incur obligations, it is expected that the trust will only incur liabilities for routine
administrative expenses, such as the Trustees fees and accounting, engineering, legal, tax
advisory and other professional fees.
FEES AND EXPENSES
The Trust is responsible for paying all legal, accounting, tax advisory, engineering, printing
and other administrative and out-of-pocket expenses incurred by or at the direction of the Trustee
or the Delaware Trustee. The Trust is also responsible for paying other expenses incurred as a
result of its being a publicly traded entity, including costs associated with annual and quarterly
reports to unitholders, tax returns and Schedule K-1 preparation and distribution, independent
auditor fees and registrar and transfer agent fees. These costs as well as those to be paid to ECA
pursuant to the Administrative Services Agreement outlined under The trust Administrative
Services Agreement and Development Agreement, will be deducted by the Trust before distributions
are made to trust unitholders. From inception until December 31, 2010, the Trust incurred
approximately $1.0 million in administrative fees including fees associated with formation and the
initial public offering.
The Administrative Services Agreement provides that the Trust is obligated, throughout the
term of the trust, to pay to ECA each quarter an administrative services fee for accounting,
bookkeeping and informational services relating to the Royalties. The annual fee, payable in equal
quarterly installments, totals $60,000 per year.
RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
The duties and liabilities of the Trustee are set forth in the trust agreement. The trust
agreement provides that (i) the Trustee shall not have any duties or liabilities, including
fiduciary duties, except as expressly set forth in the trust agreement, and (ii) the duties and
liabilities of the Trustee as set forth in the trust agreement replace any other duties and
liabilities, including fiduciary duties, to which the Trustee might otherwise be subject.
The Trustee does not make business decisions affecting the assets of the Trust. Therefore,
substantially all of the Trustees functions under the trust agreement are expected to be
ministerial in nature. See Duties and powers of the Trustee, above. The trust agreement,
however, provides that the Trustee may:
| charge for its services as Trustee; | ||
| retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the Trustee to the extent permitted by law); | ||
| lend funds at commercial rates to the trust to pay the trusts expenses; and | ||
| seek reimbursement from the trust for its out-of-pocket expenses. |
In discharging its duty to trust unitholders, the Trustee may act in its discretion and will
be liable to the trust unitholders only for fraud, gross negligence or acts or omissions
constituting bad faith. The Trustee will not be liable
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for any act or omission of its agents or employees unless the Trustee acted with fraud, in bad
faith or with gross negligence in their selection and retention. The Trustee will be indemnified
individually or as the Trustee for any liability or cost that it incurs in the administration of
the trust, except in cases of fraud, gross negligence or bad faith. The Trustee will have a lien on
the assets of the trust as security for this indemnification and its compensation earned as
Trustee. See Description of the trust units Liability of trust unitholders. The Trustee
ensures that all contractual liabilities of the trust are limited to the assets of the trust.
DURATION OF THE TRUST; SALE OF ROYALTIES
The Trust remains in existence until the Termination Date, which is March 31, 2030. The trust
dissolves prior to the Termination Date if:
| the Trust sells all of the Royalties; | ||
| gross proceeds attributable to the Royalties are less than $1.5 million for any four consecutive quarters; | ||
| the holders of a majority of the outstanding trust units vote in favor of dissolution; or | ||
| the Trust is judicially dissolved. |
The Trustee would then sell all of the Trusts assets, either by private sale or public
auction, and distribute the net proceeds of the sale to the trust unitholders.
DISPUTE RESOLUTION
Any dispute, controversy or claim that may arise between ECA and the Trustee relating to the
trust will be submitted to binding arbitration before a panel of three arbitrators.
COMPENSATION OF THE TRUSTEE AND THE DELAWARE TRUSTEE
The Trustees and the Delaware Trustees compensation is paid out of the trusts assets. See Fees and Expenses.
TAX MATTERS
Trust unitholders will be treated as partners of the Trust for federal income tax purposes.
The trust agreement contains tax provisions that generally allocate the trusts income, gain, loss,
deduction and credit among the trust unitholders in accordance with their percentage interests in
the trust. The trust agreement also sets forth the tax accounting principles to be applied by the
Trust.
MISCELLANEOUS
The Trustee may consult with counsel, accountants, tax advisors, geologists and engineers and
other parties the Trustee believes to be qualified as experts on the matters for which advice is
sought. The Trustee will be protected for any action it takes in good faith reliance upon the
opinion of the expert.
The Delaware Trustee and the Trustee may resign at any time or be removed with or without
cause at any time by a vote of not less than a majority of the outstanding trust units. Any
successor must be a bank or trust company meeting certain requirements including having combined
capital, surplus and undivided profits of at least $20 million, in the case of the Delaware
Trustee, and $100 million, in the case of the Trustee.
The principal offices of the Trustee are located at 919 Congress Avenue, Suite 500, Austin, TX
78701, and its telephone number is 1-800-852-1422.
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DESCRIPTION OF THE TRUST UNITS
Each trust unit is a unit of beneficial interest in the Trust and is entitled to receive cash
distributions from the Trust on a pro rata basis, subject to the subordination provisions described
elsewhere in this registration statement. Subject to the subordination provisions, each trust
unitholder has the same rights regarding trust units as every other trust unitholder. The Trust has
17,605,000 trust units outstanding, consisting of 13,203,750 common units and 4,401,250
subordinated units.
DISTRIBUTIONS AND INCOME COMPUTATIONS
Cash distributions to trust unitholders are expected to be made from available funds at the
Trust for each calendar quarter. Production payments due to the Trust with respect to any calendar
quarter will be accrued based on estimated production volumes attributable to the trust properties
during such quarter (as measured at ECA metering systems) and market prices for such volumes. ECA
is expected to make a payment to the Trust equal to such accrued amounts within 30 days of the end
of such calendar quarter. After receipt of such payment, the Trustee will determine for such
calendar quarter the amount of funds available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the Trust over the Trusts expenses for that
quarter. Available funds will be reduced by any cash the Trustee decides to hold as a reserve
against future liabilities. Any difference between the payment made by ECA to the Trust with
respect to a calendar quarter and the actual cash production payments relative to the trust
properties received by ECA will be netted against future payments by ECA to the Trust. As a result,
during the subordination period, the netting of such difference could result in (i) an inability by
the trust to make cash distributions in excess of applicable subordination thresholds with respect
to a subsequent calendar quarter or (ii) distributions in excess of the incentive thresholds for a
prior calendar quarter notwithstanding the fact that such shortfall or excess, respectively, would
not have existed had production payments owed to the trust been calculated on an actual cash basis.
The amount of available funds for distribution each quarter will be payable to the trust
unitholders of record on or about the 45th day following the end of such calendar quarter or such
later date as the Trustee determines is required to comply with legal or stock exchange
requirements. The Trustee expects to distribute cash on or about the 60th day (or the next
succeeding business day following such day if such day is not a business day) following such
calendar quarter to each person who was a trust unitholder of record on the quarterly record date.
Unless otherwise advised by counsel or the IRS, the Trustee will treat the income and expenses
of the Trust for each month as belonging to the trust unitholders of record on the first business
day of the month.
TRANSFER OF TRUST UNITS
Trust unitholders may transfer their trust units in accordance with the trust agreement. The
Trustee will not require either the transferor or transferee to pay a service charge for any
transfer of a trust unit. The Trustee may require payment of any tax or other governmental charge
imposed for a transfer. The Trustee may treat the owner of any trust unit as shown by its records
as the owner of the trust unit. The Trustee will not be considered to know about any claim or
demand on a trust unit by any party except the record owner. A person who acquires a trust unit
after any quarterly record date will not be entitled to the distribution relating to that quarterly
record date. Delaware law will govern all matters affecting the title, ownership or transfer of
trust units.
PERIODIC REPORTS
The Trustee will file all required trust federal and state income tax and information returns.
The Trustee will prepare and mail to trust unitholders a Schedule K-1 that trust unitholders need
to correctly report their share of the income and deductions of the trust. The Trustee will also
cause to be prepared and filed reports required to be filed under the Securities Exchange Act of
1934, as amended, and by the rules of any securities exchange or quotation system on which the
trust units are listed or admitted to trading.
Each trust unitholder and his representatives may examine, for any proper purpose, during
reasonable business hours, the records of the trust.
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LIABILITY OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same
limitation of personal liability extended to stockholders of private corporations for profit under
the General Corporation Law of the State of Delaware. No assurance can be given, however, that the
courts in jurisdictions outside of Delaware will give effect to such limitation.
VOTING RIGHTS OF TRUST UNITHOLDERS
The Trustee or trust unitholders owning at least 10% of the outstanding trust units may call
meetings of trust unitholders. The Trust will be responsible for all costs associated with calling
a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which
case the trust unitholders will be responsible for all costs associated with calling such meeting
of trust unitholders. Meetings must be held in such location as is designated by the Trustee in the
notice of such meeting. The Trustee must send written notice of the time and place of the meeting
and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than
60 days before the meeting. Trust unitholders representing a majority of trust units outstanding
must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for
each trust unit owned.
Unless otherwise required by the trust agreement, a matter may be approved or disapproved by
the vote of a majority of the trust units held by the trust unitholders at a meeting where there is
a quorum. This is true, even if a majority of the total outstanding trust units did not approve it.
The affirmative vote of the holders of a majority of the outstanding trust units is required to:
| dissolve the trust (except in accordance with its terms); | ||
| remove the Trustee or the Delaware Trustee; | ||
| amend the trust agreement, the royalty conveyances, the Administrative Services Agreement, the Development Agreement, the Drilling Support Lien, the Royalty Interest Lien and the hedge agreements (except with respect to certain matters that do not adversely affect the right of trust unitholders in any material respect); | ||
| merge or consolidate the trust with or into another entity; or | ||
| approve the sale of all or any material part of the assets of the trust. |
except that if any of the matters listed above (except removal of the Trustee or the Delaware
Trustee) would result in a materially disproportionate benefit to ECA or its affiliates compared to
other owners of common units, the affirmative vote of the holders of a majority of common units and
a majority of trust units is required.
In addition, certain amendments to the trust agreement may be made by the Trustee without
approval of the trust unitholders. The Trustee must consent before all or any part of the trust
assets can be sold except in connection with the dissolution of the trust or limited sales directed
by ECA in conjunction with its sale of Royalties.
COMPARISON OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of trust unitholders or for
annual or other periodic re-election of the Trustee.
Unitholders should also be aware of the following ways in which an investment in trust units
is different from an investment in common stock of a corporation.
Trust units | Common stock | |||
Voting
|
The trust agreement provides voting rights to trust unitholders to remove and replace (but not elect) the Trustee and to approve or disapprove major trust transactions. | Corporate statutes provide voting rights to stockholders of the corporation to elect directors and to approve or disapprove major corporate transactions. |
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Trust units | Common stock | |||
Income Tax
|
The trust is not subject to federal income tax; trust unitholders are subject to income tax on their allocable share of trust income, gain, loss and deduction. | Corporations are taxed on their income, and their stockholders are taxed on dividends. | ||
Distributions
|
Substantially all trust revenue is distributed to trust unitholders. | Stockholders receive dividends at the discretion of the board of directors. | ||
Business and Assets
|
The business of the trust is limited to specific assets with a finite economic life. | A corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand. | ||
Fiduciary Duties
|
To the extent provided in the trust agreement, the Trustee has limited its fiduciary duties in the trust agreement as permitted by the Delaware Statutory Trust Act so that it will be liable to unitholders only for fraud, gross negligence or acts or omissions constituting bad faith. | Officers and directors have a fiduciary duty of loyalty to stockholders and a duty to use due care in management and administration of a corporation. |
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FEDERAL INCOME TAX CONSIDERATIONS
This section is a discussion of the material tax considerations that may be relevant to
prospective trust unitholders who are individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P.,
counsel to ECA and the Trust, insofar as it relates to legal conclusions with respect to matters of
U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue
Code of 1986, as amended (the Internal Revenue Code), existing and proposed Treasury regulations
promulgated under the Internal Revenue Code (the Treasury Regulations) and current administrative
rulings and court decisions, all of which are subject to change. Future changes in these
authorities may cause the tax consequences to vary substantially from the consequences described
below.
The following discussion does not address all federal income tax matters affecting the Trust
or the trust unitholders. Moreover, the discussion focuses on trust unitholders who are individual
citizens or residents of the United States and has only limited application to corporations,
estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such
as tax-exempt institutions, non-U.S. persons, taxpayers subject to the alternative minimum tax,
individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts
(REITs) or mutual funds. Accordingly, the trust encourages each prospective trust unitholder to
consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax
consequences particular to him of the ownership or disposition of trust units.
No ruling has been or will be requested from the Internal Revenue Service (the IRS)
regarding any matter affecting the trust or prospective trust unitholders. Instead, the Trust is
relying on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents
only that counsels best legal judgment and does not bind the IRS or the courts. Accordingly, the
opinions and statements made herein may not be sustained by a court if contested by the IRS. Any
contest of this sort with the IRS may materially and adversely impact the market for the trust
units and the prices at which trust units trade. In addition, the costs of any contest with the
IRS, principally legal, accounting and related fees, will result in a reduction in cash available
for distribution to the trust unitholders, and thus will be borne indirectly by the trust
unitholders. Furthermore, the tax treatment of the Trust, or of an investment in the trust, may be
significantly modified by future legislative or administrative changes or court decisions. Any
modifications may or may not be retroactively applied.
All statements as to matters of law and legal conclusions, but not as to factual matters,
contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and
are based on the accuracy of the representations made by ECA and the trust.
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with
respect to the following specific federal income tax issues: (1) the treatment of a trust
unitholder whose trust units are loaned to a short seller to cover a short sale of trust units
(please read Tax consequences of trust unit ownership Treatment of short sales); (2)
whether the trusts monthly convention for allocating taxable income and losses is permitted by
existing Treasury Regulations (please read Disposition of trust units Allocations between
transferors and transferees); and (3) whether percentage depletion will be available to a trust
unitholder or the extent of the percentage depletion deduction available to any trust unitholder
(please read Tax consequences of trust unit ownership Tax treatment of the perpetual
royalties).
As used herein, the term trust unitholder means a beneficial owner of trust units that for
U.S. federal income tax purposes is:
| an individual who is a citizen of the United States or who is resident in the United States for U.S. federal income tax purposes, | ||
| a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia, | ||
| an estate the income of which is subject to U.S. federal income taxation regardless of its source, or |
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| a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a United States person. |
The term non-U.S. trust unitholder means any beneficial owner of a trust unit (other than an
entity that is classified for U.S. federal income tax purposes as a partnership or as a
disregarded entity) that is not a trust unitholder.
If an entity that is classified for U.S. federal income tax purposes as a partnership is a
beneficial owner of trust units, the tax treatment of a member of the entity will depend upon the
status of the member and the activities of the entity. The trust encourages any entity that is
classified for U.S. federal income tax purposes as a partnership and that is a beneficial owner of
trust units, and the members of such an entity, to consult their own tax advisors about the U.S.
federal income tax considerations of purchasing, owning, and disposing of trust units.
CLASSIFICATION OF THE TRUST AS A PARTNERSHIP
Although the Trust is formed as a statutory trust under Delaware law, the Trusts
classification for federal income tax purposes is based on its characteristics rather than its
form. Based on such characteristics, it is expected that, as described below, the Trust will be
treated for federal and applicable state income tax purposes as a partnership and trust unitholders
will be treated as partners in that partnership.
A partnership is not a taxable entity and incurs no federal income tax liability. Instead,
each partner of a partnership is required to take into account his share of items of income, gain,
loss, deduction and credit of the partnership in computing his federal income tax liability,
regardless of whether cash distributions are made to him by the partnership. Distributions by a
partnership to a partner are generally not taxable to the partner unless the amount of cash
distributed to him is in excess of the partners adjusted basis in his partnership interest as of
the end of the taxable year in which the distribution is made.
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as
a general rule, be taxed as corporations. However, an exception, referred to in this discussion as
the Qualifying Income Exception, exists with respect to publicly traded partnerships of which 90%
or more of the gross income for every taxable year consists of qualifying income. Qualifying
income includes income and gains derived from the exploration, development, production and
marketing of crude oil and natural gas and interest income (other than from a financial business).
Other types of qualifying income include gains from the sale of real property and income from
certain hedging transactions. The trust anticipates that substantially all of its gross income will
be qualifying income. Based upon the factual representations made by the trust and ECA and a review
of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of
the trusts gross income will constitute qualifying income.
No ruling has been or will be sought from the IRS and the IRS has made no determination as to
the Trusts status for federal income tax purposes or whether the Trusts operations generate
qualifying income under Section 7704 of the Internal Revenue Code. Instead, the Trust is relying
on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins
L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings
and court decisions and the representations described below, the Trust will be classified as a
partnership for federal income tax purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by
the trust and ECA. The representations made by the trust and ECA upon which Vinson & Elkins L.L.P.
has relied are:
(a) The Trust has not, and will not, elect to be treated as a
corporation;
(b) The Trust is, and will be organized and operated in accordance with (i) all applicable
trust statutes, including the Delaware Statutory Trust Act, (ii) the trust agreement, and (iii)
the description thereof in this prospectus;
(c)
For each taxable year, more than 90% of the trusts gross income will be income that
Vinson & Elkins L.L.P. has opined or will opine is qualifying income within the meaning of
Section 7704(d) of the Internal Revenue Code; and
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(d) Each hedging transaction that the trust treats as resulting in qualifying income will
be appropriately identified as a hedging transaction pursuant to applicable Treasury
Regulations, and will be associated with oil, gas or products thereof that are held or will be
held by the Trust in activities that Vinson & Elkins L.L.P. has opined or will opine result in
qualifying income.
The Trust believes that these representations are true and expects that these representations
will continue to be true in the future.
If the Trust fails to meet the Qualifying Income Exception, other than a failure that is
determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery
(in which case the IRS may also require the Trust to make adjustments with respect to the trusts
unitholders allocable share of trust income, gain, loss or deduction or pay other amounts), the
Trust will be treated as if it had transferred all of its assets, subject to liabilities, to a
newly formed corporation, on the first day of the year in which the Trust fails to meet the
Qualifying Income Exception, in return for stock in that corporation, and then distributed that
stock to the unitholders in liquidation of their interests in the Trust. This deemed contribution
and liquidation should be tax-free to the trust unitholders and the Trust. Thereafter, the Trust
would be treated as an association taxable as a corporation for federal income tax purposes.
If the Trust were treated as an association taxable as a corporation in any taxable year,
either as a result of a failure to meet the Qualifying Income Exception or otherwise, the trusts
items of income, gain, loss and deduction would be reflected only on the Trusts tax return rather
than being passed through to the trust unitholders, and the Trusts net income would be taxed to
the Trust at corporate rates. In addition, any distribution made to a trust unitholder would be
treated as either taxable dividend income, to the extent of the Trusts current or accumulated
earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital,
to the extent of the trust unitholders tax basis in his trust units, or taxable capital gain,
after the trust unitholders tax basis in his trust units is reduced to zero. Accordingly, taxation
as a corporation would result in a material reduction in a trust unitholders cash flow and
after-tax return and thus would likely result in a substantial reduction of the value of the trust
units.
The discussion below is based on Vinson & Elkins L.L.P.s opinion that the trust will be
classified as a partnership for federal income tax purposes.
PARTNER STATUS
Trust unitholders will be treated as partners of the Trust for federal income tax purposes.
Also, trust unitholders whose trust units are held in street name or by a nominee and who have the
right to direct the nominee in the exercise of all substantive rights attendant to the ownership of
their trust units will be treated as partners of the Trust for federal income tax purposes.
A beneficial owner of trust units whose trust units have been transferred to a short seller to
complete a short sale would appear, as a result, to lose his status as a partner with respect to
those trust units for federal income tax purposes. Please read Tax consequences of trust unit
ownership Treatment of short sales. Income, gain, deductions or losses would not appear to be
reportable by a trust unitholder who is not a partner for federal income tax purposes, and any cash
distributions received by a trust unitholder who is not a partner for federal income tax purposes
would therefore appear to be fully taxable as ordinary income. These unitholders are urged to
consult their own tax advisors with respect to their tax considerations related to holding trust
units. The references to unitholders in the discussion that follows are to persons who are
treated as partners in the Trust for federal income tax purposes.
TAX CLASSIFICATION OF THE PDP ROYALTY INTEREST AND THE PUD ROYALTY INTEREST
For federal income tax purposes, a mineral interest similar to the PDP Royalty Interest and
the PUD Royalty Interest will have the tax characteristics of a mineral royalty interest to the
extent, at the time of its creation, such mineral interest is reasonably expected to have an
economic life that corresponds substantially to the economic life of the mineral property or
properties burdened thereby. Payments out of production that are received in respect of a mineral
interest that constitutes a royalty interest for federal income tax purposes are taxable under
current law as ordinary income subject to an allowance for cost or percentage depletion in respect
of such income.
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In contrast, a mineral interest similar to the PDP Royalty Interest and the PUD Royalty
Interest will have the tax characteristics of production payments governed by Section 636 of the
Internal Revenue Code to the extent, at the time of their creation, such a mineral interest is not
reasonably expected to extend in substantial amounts over the entire productive life of the mineral
property or properties it burdens. Payments out of production that are received in respect of a
mineral interest that constitutes a production payment for federal income tax purposes are treated
under current law as consisting of a receipt of principal and interest on a nonrecourse debt
obligation, with the interest component being taxable as ordinary income.
In the event that a portion of a single royalty interest terminates by its terms prior to the
point in time that the economically productive life of the burdened mineral property is
substantially exhausted and the remaining portion continues to burden the property until its
economically productive life is substantially exhausted, the federal income tax characteristics of
the royalty interest are determined as if it comprised two separate interests, with the terminating
portion being treated as a production payment and the continuing portion being treated as a royalty
interest.
Based on the reserve report described in the Initial Prospectus and representations made by
ECA regarding the expected economic life of the Underlying Properties and the expected duration of
the Term Royalties and the Perpetual Royalties, the Term PDP Royalty will and the Term PUD Royalty
should be treated as production payments under Section 636 of the Internal Revenue Code, and thus
as nonrecourse debt instruments of ECA for U.S. federal income tax purposes. The Perpetual PDP
Royalty will and the Perpetual PUD Royalty should be treated as continuing, nonoperating economic
interest in the nature of royalties payable out of production from the mineral interests they
burden.
Consistent with this characterization, ECA and the trust treat the Perpetual Royalties as
mineral royalty interests for federal income tax purposes. In addition, ECA and the Trust treat the
Term Royalties as debt instruments for U.S. federal income tax purposes subject to the Treasury
Regulations applicable to contingent payment debt instruments (the CPDI regulations), and the
trust has agreed to be bound by ECAs application of the CPDI regulations, including ECAs
determination of the rate at which interest is deemed to accrue on such interests. The remainder of
this discussion assumes that the Term Royalties are treated in accordance with that agreement and
ECAs determinations that the Perpetual Royalties are treated as mineral royalty interests. No
assurance can be given that the IRS will not assert that such interests should be treated
differently. Such different treatment could affect the amount, timing and character of income, gain
or loss in respect of an investment in trust units and could require a trust unitholder to accrue
interest income at a rate different than the comparable yield described below. Please read
Tax consequences of trust unit ownership Tax treatment of the term royalties, and Tax
consequences of trust unit ownership Tax treatment of the perpetual royalties.
TAX CONSEQUENCES OF TRUST UNIT OWNERSHIP
Flow-Through of Taxable Income
As a partnership for federal income tax purposes, the Trust is not a taxable entity required
to pay any federal income tax. Instead, each trust unitholder will be required to report on his
income tax return his allocable share of the Trusts income, gains, losses, deductions and credits
without regard to whether the trust makes cash distributions to him. Consequently, the trust may
allocate taxable income to a trust unitholder even if he has not received a cash distribution.
Accounting Method and Taxable Year
The Trust uses the year ending December 31 as its taxable year and the accrual method of
accounting for federal income tax purposes. Each trust unitholder is required to include in income
his share of the trusts income, gain, loss, deduction and credit for the trusts taxable year
ending within or with his taxable year. In addition, a trust unitholder who has a taxable year
ending on a date other than December 31 and who disposes of all of his trust units following the
close of the Trusts taxable year but before the close of his taxable year must include his share
of the Trusts income, gain, loss, deduction and credit in his taxable income for his taxable year,
with the result that he is required to include in income for his taxable year his share of more
than twelve months of the trusts income, gain, loss, deduction and credit. Please read
Disposition of trust units Allocations between transferors and transferees.
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Basis of Trust Units
A trust unitholders initial tax basis for his trust units is the amount he paid for the trust
units. That basis will be increased by his share of the Trusts income and gain and decreased, but
not below zero, by distributions from the Trust, by the trust unitholders share of the Trusts
losses, if any, by depletion deductions taken by him to the extent such deductions do not exceed
his proportionate allocated share of the adjusted tax basis of the Perpetual Royalties, and by his
share of the Trusts expenditures that are not deductible in computing taxable income and are not
required to be capitalized. Please read Disposition of trust units Recognition of gain or
loss.
Allocation of Income, Gain, Loss, Deduction and Credit
In general, if the Trust has a net profit, the Trusts items of income, gain, loss, deduction
and credit will be allocated among the trust unitholders in accordance with their percentage
interests in the Trust. At any time that distributions are made to the common units in excess of
distributions to the subordinated trust units, or incentive distributions are made in respect of
the subordinated trust units, gross income will be allocated to the recipients to the extent of
these distributions. If the Trust has a net loss, that loss will be allocated first to the
subordinated trust units to the extent of their positive capital accounts and thereafter to the
trust unitholders in accordance with their percentage interests in the Trust.
Specified items of the Trusts income, gain, loss, deduction and credit will be allocated
under Section 704(c) of the Internal Revenue Code to account for any difference between the tax
basis and fair market value of any property treated as having been contributed to the Trust by ECA
or certain of its affiliates that existed at the time of such contribution, together, referred to in
this discussion as the Contributed Property. These Section 704(c) Allocations are required to
eliminate the difference between a partners book capital account, credited with the fair market
value of Contributed Property, and the tax capital account, credited with the tax bases of
Contributed Property, referred to in this discussion as the Book-Tax Disparity.
Finally, although the Trust does not expect that its
operations will result in the creation of negative capital accounts, if negative capital accounts
nevertheless result, items of the Trusts income and gain will be allocated in an amount and manner
sufficient to eliminate the negative balance as quickly as possible.
An allocation of items of the Trusts income, gain, loss, deduction or credit, other than an
allocation required by Section 704(c) of the Internal Revenue Code to eliminate the Book-Tax
Disparity, will generally be given effect for federal income tax purposes in determining a
unitholders share of an item of income, gain, loss, deduction or credit only if the allocation has
substantial economic effect. In any other case, a unitholders share of an item will be determined
on the basis of his interest in the trust, which will be determined by taking into account all the
facts and circumstances, including:
| his relative contributions to the trust; | ||
| the interests of all the partners in profits and losses; | ||
| the interest of all the partners in cash flow; and | ||
| the rights of all the partners to distributions of capital upon liquidation. |
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in
Disposition of trust units Allocations between transferors and transferees, allocations under
the trust agreement will be given effect for federal income tax
purposes in determining a trust unitholders
share of an item of income, gain, loss, deduction or credit.
Treatment of Trust Distributions
Distributions by the Trust to a trust unitholder generally will not be taxable to the trust
unitholder for federal income tax purposes, except to the extent the amount of any such cash
distribution exceeds his tax basis in his trust units immediately before the distribution. The
Trusts cash distributions in excess of a unitholders tax basis (if any)
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generally will be considered to be gain from the sale or exchange of the trust units, taxable
in accordance with the rules described under Disposition of trust units below.
Ratio of Taxable Income to Distributions
The Trust estimates that a purchaser of trust units
in this offering who owns those
trust units through the record date for
distributions for the period ending December 31, 2013, would be allocated, on a cumulative basis,
an amount of federal taxable income for that period that would be approximately 65% or less of the
cash distributed with respect to that period. These estimates and assumptions are subject to, among
other things, numerous business, economic, regulatory, legislative, competitive and political
uncertainties beyond the trusts control. Further, the estimates were based on current tax law and
tax reporting positions that the trust adopted and with which the IRS could disagree. Accordingly,
the Trust cannot assure unitholders that these estimates will prove to be correct. The actual
percentage of distributions that will correspond to taxable income could be higher or lower than
expected, and any differences could be material and could materially affect the value of the trust
units.
Tax Treatment of the Term Royalties
Under the CPDI regulations, the Trust generally is required to accrue income on the Term
Royalties which are treated as production payments, and therefore as nonrecourse debt obligations
of ECA for federal income tax purposes, in the amounts described below.
The CPDI regulations provide that the trust must accrue an amount of ordinary interest income
for U.S. federal income tax purposes, for each accrual period prior to and including the maturity
date of the debt instrument that equals:
| the product of (i) the adjusted issue price (as defined below) of the debt instrument as of the beginning of the accrual period; and (ii) the comparable yield to maturity (as defined below) of such debt instrument, adjusted for the length of the accrual period; | ||
| divided by the number of days in the accrual period; and | ||
| multiplied by the number of days during the accrual period that the trust held the debt instrument. |
The
initial issue price of the debt instrument represented by each production payment held by the
trust was the portion of the first price at which a substantial
amount of the trust units was sold to
the public, excluding sales to bond houses, brokers or similar persons or organizations acting in
the capacity of underwriters, placement agents or wholesalers, that is allocable to the production
payment based on the relative fair market value of the production payment to the other assets of
the trust. The adjusted issue price of such a debt
instrument is its initial issue price increased by any
interest income previously accrued, determined without regard to any adjustments to interest
accruals described below, and decreased by the projected amount of any payments scheduled to be
made with respect to the debt instrument at an earlier time (without regard to the actual amount
paid). The term comparable yield means the annual yield
ECA would have been expected to pay, as of the
initial issue date, on a fixed rate debt security with no contingent payments but with terms and
conditions otherwise comparable to those of the debt instrument represented by the production
payment.
ECA and the Trust take the position that the comparable yield for each debt instrument held by
the Trust is an annual rate of 10%, compounded semi-annually. The CPDI regulations require and ECA
provided to the Trust, solely for determining the amount of interest accruals for U.S. federal
income tax purposes, a schedule of the projected amounts of payments, which are referred to as
projected payments, on the Term Royalties treated as debt instruments held by the Trust. These
payments set forth on the schedule must produce a total return on such debt instruments equal to
their comparable yield. Amounts treated as interest under the CPDI regulations are treated as
original issue discount for all purposes of the Internal Revenue Code.
As required by the CPDI regulations, for U.S. federal income tax purposes, the Trust must use
the comparable yield and the schedule of projected payments as described above in determining the
trusts interest accruals, and the adjustments thereto described below, in respect of the debt
instruments held by the Trust.
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ECAs determinations of the comparable yield and the projected payment schedule are not
binding on the IRS and it could challenge such determinations. If it did so, and if any such
challenge were successful, then the amount and timing of interest income accruals of the Trust
would be different from those reported by the trust or included on previously filed tax returns by
the trust unitholders.
The comparable yield and the schedule of projected payments were not determined for any
purpose other than for the determination for U.S. federal income tax purposes of the Trusts
interest accruals and adjustments thereof in respect of the debt instruments held by the Trust and
do not constitute a projection or representation regarding the actual amounts payable to the Trust.
For U.S. federal income tax purposes, the Trust is required under the CPDI regulations to use
the comparable yield and the projected payment schedule established by ECA in determining interest
accruals and adjustments in respect of the production payments. Pursuant to the terms of the
conveyance, ECA and the Trust have agreed (in the absence of an administrative determination or
judicial ruling to the contrary) to be bound by ECAs determination of the comparable yield and
projected payment schedule.
If, during any taxable year, the Trust receives actual payments with respect to a debt
instrument held by the Trust that in the aggregate exceed the total amount of projected payments
for that taxable year, the trust will incur a net positive adjustment under the CPDI regulations
equal to the amount of such excess. The Trust will treat a net positive adjustment as additional
interest income for such taxable year.
If the Trust receives in a taxable year actual payments with respect to a debt instrument held
by the Trust that in the aggregate are less than the amount of projected payments for that taxable
year, the trust will incur a net negative adjustment under the CPDI regulations equal to the
amount of such deficit. This adjustment will (a) reduce the Trusts interest income on the debt
instrument held by the Trust for that taxable year, and (b) to the extent of any excess after the
application of (a) give rise to an ordinary loss to the extent of the trusts interest income on
such debt instrument during prior taxable years, reduced to the extent such interest was offset by
prior net negative adjustments. Any negative adjustment in excess of the amount described in (a)
and (b) will be carried forward, as a negative adjustment to offset future interest income in
respect of that debt instrument held by the Trust. If either of the Term Royalties is not treated
as a production payment (and not otherwise as a debt instrument) for federal income tax purposes,
the trust intends to take the position that its basis in the Term Royalty is recouped in proportion
to the production from the Term Royalty.
Neither the Trust nor the trust unitholders are entitled to claim depletion deductions with
respect to the Term Royalties.
Tax Treatment of the Perpetual Royalties
The payments received by the Trust in respect of the Perpetual Royalties treated as mineral
royalty interests for federal income tax purposes will be treated as ordinary income. Trust
unitholders will be entitled to deductions for the greater of either cost depletion or (if
otherwise allowable) percentage depletion with respect to such income. Although the Internal
Revenue Code requires each trust unitholder to compute his own depletion allowance and maintain
records of his share of the adjusted tax basis of the underlying Perpetual Royalties for depletion
and other purposes, the Trust will furnish each of the trust unitholders with information relating
to this computation for federal income tax purposes. Each trust unitholder, however, remains
responsible for calculating his own depletion allowance and maintaining records of his share of the
adjusted tax basis of the Perpetual Royalties for depletion and other purposes.
Percentage depletion is generally available with respect to trust unitholders who qualify
under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code.
For this purpose, an independent producer is a person not directly or indirectly involved in the
retail sale of oil, natural gas, or derivative products or the operation of a major refinery.
Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of
marginal production, potentially a higher percentage) of the trust unitholders gross income from
the depletable property for the taxable year. The percentage depletion deduction with respect to
any property is limited to 100% of the taxable income of the trust unitholder from the property for
each taxable year, computed without the depletion allowance. A trust unitholder that qualifies as
an independent producer may deduct percentage depletion only to the extent the trust unitholders
average daily production of domestic crude oil, or the natural gas equivalent,
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does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural
gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to
one barrel of crude oil. The 1,000-barrel limitation must be allocated among the independent
producer and controlled or related persons and family members in proportion to the respective
production by such persons during the period in question.
In addition to the foregoing limitations, the percentage depletion deduction otherwise
available is limited to 65% of a trust unitholders total taxable income from all sources for the
year, computed without the depletion allowance, net operating loss carrybacks, or capital loss
carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be
deducted in the following taxable year if the percentage depletion deduction for such year plus the
deduction carryover does not exceed 65% of the trust unitholders total taxable income for that
year. The carryover period resulting from the 65% net income limitation is unlimited.
In addition to the limitations on percentage depletion discussed above, on February 14, 2011,
the White House released President Obamas budget proposal for the fiscal year 2012 (the 2012
Budget). The 2012 Budget proposes to eliminate certain tax preferences applicable to taxpayers
engaged in the exploration or production of natural resources effective in 2012. Specifically, the
2012 Budget proposes to repeal the deduction for percentage depletion with respect to oil and
natural gas wells, in which case only cost depletion would be available. It is uncertain whether
this or any other legislative proposals will ever be enacted and, if so, when any such proposal
would become effective.
Trust unitholders that do not qualify under the independent producer exemption are generally
restricted to depletion deductions based on cost depletion. Cost depletion deductions are
calculated by (i) dividing the trust unitholders allocated share of the adjusted tax basis in the
underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet,
or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the
result by the number of mineral units sold within the taxable year. The total amount of deductions
based on cost depletion cannot exceed the trust unitholders share of the total adjusted tax basis
in the property.
The foregoing discussion of depletion deductions does not purport to be a complete analysis of
the complex legislation and Treasury Regulations relating to the availability and calculation of
depletion deductions by the trust unitholders. Further, because depletion is required to be
computed separately by each trust unitholder and not by the Trust, no assurance can be given, and
counsel is unable to express any opinion, with respect to the availability or extent of percentage
depletion deductions to the trust unitholders for any taxable year. The Trust encourages each
prospective trust unitholder to consult his tax advisor to determine whether percentage depletion
would be available to him.
Tax Treatment Upon Sale of the Perpetual Royalties at Termination Date
The sale of the Perpetual Royalties by the Trust at or shortly after the Termination Date will
generally give rise to long-term capital gain or loss to the trust unitholders for federal income
tax purposes, except that any gain will be taxed at ordinary income rates to the extent of
depletion deductions that reduced the trust unitholders adjusted basis in the Perpetual Royalties.
Each trust unitholder will be responsible for calculating his gain or loss based on the difference
between his pro-rata share of the amount realized on the sale by the Trust and his adjusted basis
in the Perpetual Royalties, and if a gain is realized, the portion thereof taxable as ordinary
income by reason of depletion deductions previously claimed by such trust unitholder. However, the
trust intends to furnish each of the trust unitholders with information relating to this
calculation for federal income tax purposes in connection with the final partnership tax return for
the Trust.
Limitations on Deductibility of Losses
It is not anticipated that the Trust will generate losses. Nevertheless, should losses result,
trust unitholders must consult their own tax advisors as to the applicability to them of loss
limitation rules that could operate to limit the deductibility to a trust unitholder of his share
of the Trusts losses such as the basis limitation, the at risk rules and the passive loss rules.
Special passive loss limitation rules apply with respect to publicly-traded partnerships.
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Limitations on Interest Deductions
The deductibility of a non-corporate taxpayers investment interest expense is generally
limited to the amount of that taxpayers net investment income. Investment interest expense
includes:
| interest on indebtedness properly allocable to property held for investment; | ||
| the Trusts interest expense attributed to portfolio income; and | ||
| the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income. |
The computation of a trust unitholders investment interest expense will take into account
interest on any margin account borrowing or other loan incurred to purchase or carry a trust unit.
Net investment income includes gross income from property held for investment and amounts treated
as portfolio income under the passive loss rules, less deductible expenses, other than interest,
directly connected with the production of investment income, but generally does not include gains
attributable to the disposition of property held for investment or qualified dividend income. The
IRS has indicated that the net passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders for purposes of the investment interest deduction
limitation. In addition, the trust unitholders share of the trusts portfolio income will be
treated as investment income.
Entity-Level Withholdings
If the Trust is required or elects under applicable law to pay any federal, state, local or
foreign income tax on behalf of any trust unitholder or any former trust unitholder, the trust is
authorized to pay those taxes from its funds. That payment, if made, will be treated as a
distribution of cash to the trust unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be determined, the trust is authorized to treat
the payment as a distribution to all current trust unitholders. The Trust is authorized to amend
its trust agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics
of trust units. Payments by the trust as described above could give rise to an overpayment of tax
on behalf of an individual trust unitholder in which event the trust unitholder would be required
to file a claim in order to obtain a credit or refund.
Treatment of Short Sales
A trust unitholder whose trust units are loaned to a short seller to cover a short sale of
trust units may be considered as having disposed of those units. If so, he would no longer be
treated for tax purposes as a partner with respect to those trust units during the period of the
loan and may recognize gain or loss from the disposition. As a result, during this period:
| any of the trusts income, gain, loss, deduction or credit with respect to those trust units would not be reportable by the trust unitholder; | ||
| any cash distributions received by the trust unitholder as to those trust units would be fully taxable; and | ||
| all of these distributions would appear to be ordinary income. |
Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a trust
unitholder whose trust units are loaned to a short seller to cover a short sale of trust units;
therefore, trust unitholders desiring to assure their status as partners and avoid the risk of gain
recognition from a loan to a short seller are urged to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing and loaning their trust units. The IRS has
previously announced that it is studying issues relating to the tax treatment of short sales of
partnership interests. Please also read Disposition of trust units Recognition of gain or
loss.
Alternative Minimum Tax
Each trust unitholder will be required to take into account his distributive share of any
items of the Trusts income, gain, loss, deduction or credit for purposes of the alternative
minimum tax. The current minimum tax rate
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for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income
in excess of the exemption amount and 28% on any additional alternative minimum taxable income.
Prospective trust unitholders are urged to consult with their tax advisors as to the impact of an
investment in trust units on their liability for the alternative minimum tax.
Tax Rates
Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary
income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to
long-term capital gains (generally, capital gains on certain assets held for more than 12 months)
of individuals is 15%. However, absent new legislation extending the current rates, beginning
January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income
and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover,
these rates are subject to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8%
Medicare tax on certain investment income earned by individuals for taxable years beginning after
December 31, 2012. For these purposes, investment income generally includes a trust unitholders
allocable share of the trusts income and gain realized by a trust unitholder from a sale of trust
units. The tax will be imposed on the lesser of (i) the trust unitholders net income from all
investments, and (ii) the amount by which the trust unitholders adjusted gross income exceeds
$250,000 (if the trust unitholder is married and filing jointly) or $200,000 (if the trust
unitholder is not married).
Section 754 Election
The
Trust made the election permitted by Section 754 of the Internal Revenue Code. That
election is irrevocable without the consent of the IRS. The election will generally permit the
trust to adjust a trust unit purchasers tax basis in the Trusts assets (inside
basis) under Section 743(b) of the Internal Revenue Code to reflect his purchase price of trust
units acquired from another trust unitholder. The Section 743(b) adjustment belongs to the
purchaser and not to other trust unitholders. For purposes of this discussion, a trust unitholders
inside basis in the trusts assets will be considered to have two components: (1) his share of tax
basis in the Trusts assets (common basis) and (2) his Section 743(b) adjustment to that basis.
A Section 754 election is advantageous if the transferees tax basis in his units is higher
than the units share of the aggregate tax basis of the Trusts assets immediately prior to the
transfer. In such a case, as a result of the election, the transferee would have a higher tax basis
in his share of the Trusts assets for purposes of calculating, among other items, cost depletion
deductions on the Perpetual Royalties, and his share of any gain on a
sale of the Trusts assets
would be less. Conversely, a Section 754 election is disadvantageous if the transferees tax basis
in his units is lower than those trust units share of the
aggregate tax basis of the Trusts
assets immediately prior to the transfer. Thus, the fair market value of the trust units may be
affected either favorably or unfavorably by the election. A basis adjustment is required regardless
of whether a Section 754 election is made in the case of a transfer of an interest in the trust if
it has a substantial built-in loss immediately after the transfer. Generally a built in loss or
a basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are complex and will be made on the
basis of assumptions as to the value of the Trusts assets and other matters. For example, the
allocation of the Section 743(b) adjustment among the trusts assets must be made in accordance
with the Internal Revenue Code. The trust cannot assure unitholders that the determinations it
makes will not be successfully challenged by the IRS and that the deductions resulting from them
will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment
to be made, and should, in the Trusts opinion, the expense of compliance exceed the benefit of the
election, the Trust may seek permission from the IRS to revoke its Section 754 election. If
permission is granted, a subsequent purchaser of trust units may be allocated more income than he
would have been allocated had the election not been revoked.
Initial Tax Basis and Amortization
The initial tax basis of the portion of the PDP Royalty Interest treated as a royalty interest
in minerals and the portion treated as a production payment, and the initial basis of the portion
of the PUD Royalty Interest treated as a
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royalty interest in minerals and the portion treated as a production payment were effectively
equal on a per-unit basis to the portion of the unit price allocated to each based on each such
portions relative fair market value.
The costs incurred in selling the trust units in connection with the initial public offering
(called syndication expenses) must be capitalized and cannot be deducted currently, ratably or
upon the Trusts termination. There are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by the trust, and as syndication expenses, which may
not be amortized by the Trust. The underwriting discounts and
commissions the Trust incurs will be
treated as syndication expenses.
Valuation and Tax Basis of the Trusts Properties
The federal income tax consequences of the ownership and disposition of trust units will
depend in part on the Trusts estimates of the relative fair market values, and the initial tax
bases, of the Trusts assets. Although the trust may from time to time consult with professional
appraisers regarding valuation matters, the trust will make many of the relative fair market value
estimates itself. These estimates and determinations of basis are subject to challenge and will not
be binding on the IRS or the courts. If the estimates of fair market value or basis are later found
to be incorrect, the character and amount of items of income, gain, loss or deductions previously
reported by trust unitholders might change, and trust unitholders might be required to adjust their
tax liability for prior years and incur interest and penalties with respect to those adjustments.
DISPOSITION OF TRUST UNITS
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of trust units equal to the difference between the
amount realized and the trust unitholders tax basis for the trust units sold. A trust unitholders
amount realized will be measured by the sum of the cash or the fair market value of other property
received. The amount realized should be reduced by the unused net negative adjustments attributable
to the trust units disposed of as described above under Tax Consequences of trust unit
ownership Tax treatment of the term royalties. A trust unitholders adjusted tax basis in his
trust units will be equal to the trust unitholders original purchase price for the trust units,
increased by income and decreased by losses or deductions previously allocated to the trust
unitholder and by distributions to the trust unitholder and depletion deductions claimed by the
trust unitholder.
Prior
distributions from the Trust in excess of cumulative net taxable income for a trust unit
that decreased a unitholders tax basis in that trust unit will, in effect, become taxable income
if the trust unit is sold at a price greater than the trust unitholders tax basis in that trust
unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a trust unitholder, other than a dealer in
trust units, on the sale or exchange of a trust unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of trust units held for more than twelve
months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December
31, 2012 and 20% thereafter (absent new legislation extending or adjusting the current rate).
However, a portion, which will likely be substantial, of this gain or loss will be separately
computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to unrealized receivables the trust owns. The term
unrealized receivables includes potential recapture items, including depletion recapture.
Ordinary income attributable to unrealized receivables such as depletion recapture may exceed net
taxable gain realized upon the sale of a trust unit and may be recognized even if there is a net
taxable loss realized on the sale of a trust unit. Thus, a trust unitholder may recognize both
ordinary income and a capital loss upon a sale of trust units. Net capital losses may offset
capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only
be used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate
transactions must combine those interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of those interests, a portion of that
tax basis must be allocated to the interests sold using an equitable apportionment method, which
generally means that the tax basis allocated to the interest sold equals an amount that bears the
same relation to the partners tax basis in his entire interest in the partnership as the value of
the interest sold bears to the value of the partners entire interest in the partnership. Treasury
Regulations under Section 1223 of
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the Internal Revenue Code allow a selling trust unitholder who can identify trust units
transferred with an ascertainable holding period to elect to use the actual holding period of the
trust units transferred. Thus, according to the ruling discussed above, a trust unitholder will be
unable to select high or low basis trust units to sell as would be the case with corporate stock,
but, according to the Treasury Regulations, he may designate specific trust units sold for purposes
of determining the holding period of trust units transferred. A trust unitholder electing to use
the actual holding period of trust units transferred must consistently use that identification
method for all subsequent sales or exchanges of trust units. A trust unitholder considering the
purchase of additional trust units or a sale of trust units purchased in separate transactions is
urged to consult his tax advisor as to the possible consequences of this ruling and application of
the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial
products and securities, including partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain would be recognized if it were sold, assigned
or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
| a short sale; | ||
| an offsetting notional principal contract; or | ||
| a futures or forward contract with respect to the partnership interest or substantially identical property. |
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional
principal contract or a futures or forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the taxpayer or a related person then
acquires the partnership interest or substantially identical property. The Secretary of the
Treasury is also authorized to issue regulations that treat a taxpayer that enters into
transactions or positions that have substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations Between Transferors and Transferees
In
general, the Trusts taxable income and losses will be determined annually, will be
allocated on a monthly basis and will be subsequently apportioned among the trust unitholders in
proportion to the number of trust units owned by each of them as of the opening of the applicable
exchange on which the trust units are then traded on the first business day of the month, which is
referred to in this prospectus as the Allocation Date. However, gain or loss realized on a sale
or other disposition of the Trusts assets other than in the ordinary course of business will be
allocated among the trust unitholders on the Allocation Date in the month in which that gain or
loss is recognized. As a result, a trust unitholder transferring trust units may be allocated
income, gain, loss and deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the Internal Revenue Code, and most
publicly traded partnerships use similar simplifying conventions, the use of this method may not be
permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury
and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a
publicly traded partnership may use a similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax items must be prorated on a daily
basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury
Regulations; however, they are not binding on the IRS and are subject to change until final
Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the
validity of this method of allocating income and deductions between transferor and transferee trust
unitholders. If this method is not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the trust unitholders interest,
the Trusts taxable income or losses
might be reallocated among the trust unitholders. The Trust is authorized to revise its method of
allocation between transferor and transferee trust unitholders, as well as trust unitholders whose
interests vary during a taxable year, to conform to a method permitted under future Treasury
Regulations.
A trust unitholder who owns trust units at any time during a quarter and who disposes of them
prior to the record date set for a cash distribution for that quarter will be allocated items of
the Trusts income, gain, loss and deductions attributable to that quarter but will not be entitled
to receive that cash distribution.
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Notification Requirements
A
trust unitholder who sells any of his trust units is generally required to notify the Trust
in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year
following the sale). A purchaser of trust units who purchases trust units from another trust
unitholder is also generally required to notify the trust in writing of that purchase within 30
days after the purchase. Upon receiving such notifications, the Trust is required to notify the IRS
of that transaction and to furnish specified information to the transferor and transferee. Failure
to notify the Trust of a purchase may, in some cases, lead to the imposition of penalties. However,
these reporting requirements do not apply to a sale by an individual who is a citizen of the United
States and who affects the sale or exchange through a broker who will satisfy such requirements.
Constructive Termination
The
Trust will be considered to have been terminated for tax purposes if there are sales or
exchanges which, in the aggregate, constitute 50% or more of the
total interests in the Trusts
capital and profits within a twelve-month period. For purposes of measuring whether the 50%
threshold is reached, multiple sales of the same interest are counted only once. A constructive
termination results in the closing of the Trusts taxable year for all trust unitholders. In the
case of a trust unitholder reporting on a taxable year other than a calendar year, the closing of
the Trusts taxable year may result in more than twelve months
of the Trusts taxable income or
loss being includable in his taxable income for the year of termination. A constructive termination
occurring on a date other than December 31 will result in the trust filing two tax returns (and
trust unitholders may receive two Schedule K-1s) for one fiscal year and the cost of the
preparation of these returns will be borne by all trust unitholders.
The IRS has recently announced a relief procedure whereby the IRS may permit a
publicly traded partnership that has constructively terminated to provide only
a single Schedule K-1 to unitholders for the tax years in which termination occurs.
The Trust would be required to
make new tax elections after a termination, including a new election under Section 754 of the
Internal Revenue Code. A termination could also result in penalties if the trust was unable to
determine that the termination had occurred. Moreover, a termination might either accelerate the
application of, or subject the Trust to, any tax legislation enacted before the termination.
TAX EXEMPT ORGANIZATIONS AND OTHER INVESTORS
Ownership of trust units by employee benefit plans, other tax-exempt organizations,
non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those
investors and, as described below, may have substantially adverse tax consequences to them. If a
potential investor is a tax-exempt entity or a non-U.S. person, then it should consult a tax
advisor before investing in the trust units.
Tax Exempt Organizations
Employee benefit plans and most other organizations exempt from federal income tax including
IRAs and other retirement plans are subject to federal income tax on unrelated business taxable
income. Because all of the income of the trust is expected to be royalty income, interest income,
hedging income and gain from the sale of real property, none of which is unrelated business taxable
income, any such organization exempt from federal income tax is not expected to be taxable on
income generated by ownership of trust units so long as neither the property held by the trust nor
the trust units are debt-financed property within the meaning of Section 514(b) of the Internal
Revenue Code. In general, trust property would be debt-financed if the trust incurs debt to acquire
the property or otherwise incurs or maintains a debt that would not have been incurred or
maintained if the property had not been acquired and a trust unit would be debt-financed if the
trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that
would not have been incurred or maintained if the trust unit had not been acquired. All or a
portion of the floor hedging income may be treated as debt financed income treated as unrelated
business taxable income.
Non-U.S. Persons
The
Trust (or the appropriate intermediary if units are held in street name) will be
required to withhold (at a 30% rate or lower applicable treaty rate) on interest and royalty income
allocable to non-U.S. trust unitholders.
Moreover, each of the PDP and PUD Royalty Interests will be treated as a United States real
property interest for U.S. federal income tax purposes. However, as long as the trust units are
regularly traded on an established
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securities market, gain realized by a non-U.S. trust unitholder on a sale of trust units will
be subject to federal income tax only if:
| the gain is, or is treated as, effectively connected with business conducted by the non-U.S. trust unitholder in the United States, and in the case of an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by the non-U.S. trust unitholder; | ||
| the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale and certain other conditions are met; or | ||
| the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly or by applying certain attribution rules, more than 5% of the trust units. |
ADMINISTRATIVE MATTERS
Trust Information Returns and Audit Procedures
The
Trust intends to furnish to each trust unitholder, within 90 days after the close of each
calendar year, specific tax information, including a Schedule K-1, which describes his share of the
trusts income, gain, loss and deduction for the trusts preceding taxable year. In preparing this
information, which will not be reviewed by counsel, the Trust will take various accounting and
reporting positions, some of which have been mentioned earlier, to determine each trust
unitholders share of income, gain, loss and deduction. The Trust cannot assure unitholders that
those positions will yield a result that conforms to the requirements of the Internal Revenue Code,
Treasury Regulations or administrative interpretations of the IRS. Neither the trust nor Vinson &
Elkins L.L.P. can assure prospective trust unitholders that the IRS will not successfully contend
in court that those positions are impermissible. Any challenge by the IRS could negatively affect
the value of the units.
The
IRS may audit the Trusts federal income tax information returns. Adjustments resulting
from an IRS audit may require each trust unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a trust unitholders return could
result in adjustments not related to the Trusts returns as well
as those related to the Trusts
returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits,
judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax
treatment of partnership items of income, gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the partners. The Internal Revenue Code
requires that one partner be designated as the Tax Matters Partner for these purposes. The trust
agreement names ECA as the trusts Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on behalf of the trust and the
trust unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against trust unitholders for items in the trusts returns. The Tax
Matters Partner may bind a trust unitholder with less than a 1% profits interest in the trust to a
settlement with the IRS unless that trust unitholder elects, by filing a statement with the IRS,
not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial
review, by which all the trust unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be
sought by any trust unitholder having at least a 1% interest in profits or by any group of trust
unitholders having in the aggregate at least a 5% interest in profits. However, only one action for
judicial review will go forward, and each trust unitholder with an interest in the outcome may
participate.
A trust unitholder must file a statement with the IRS identifying the treatment of any item on
his federal income tax return that is not consistent with the treatment of the item on the trusts
return. Intentional or negligent disregard of this consistency requirement may subject a trust
unitholder to substantial penalties.
Nominee Reporting
Persons
who hold an interest in the Trust as a nominee for another person are required to
furnish to the trust:
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(a) | the name, address and taxpayer identification number of the beneficial owner and the nominee; | ||
(b) | whether the beneficial owner is: |
1. | a person that is not a United States person; | ||
2. | a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or | ||
3. | a tax-exempt entity; |
(c) | the amount and description of units held, acquired or transferred for the beneficial owner; and |
(d) specific information including the dates of acquisitions and transfers, means of
acquisitions and transfers and acquisition cost for purchases, as well as the amount of net
proceeds from sales.
Brokers and financial institutions are required to furnish additional information, including
whether they are United States persons and specific information on units they acquire, hold or
transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per
calendar year, is imposed by the Internal Revenue Code for failure to report that information to
the trust. The nominee is required to supply the beneficial owner of the trust units with the
information furnished to the Trust.
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STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information regarding state income
taxes and other state tax matters affecting individuals who are trust unitholders. Trust
unitholders are urged to consult their own legal and tax advisors with respect to these matters.
Prospective investors should consider state and local tax consequences of an investment in the
common units. The trust owns the Royalties burdening specified gas properties located in Greene
County, Pennsylvania. The state of Pennsylvania has income taxes applicable to individuals, but
currently does not require the trust to withhold taxes from distributions made to nonresident
unitholders. If withholding were required under current Pennsylvanian law, the rate would be 3.07%
of taxable income attributable to Pennsylvania. A trust unitholder may be required to file state
income tax returns and/or pay taxes in Pennsylvania and may be subject to penalties for failure to
comply with such requirements. Taxes withheld by the trust would be treated as deductions against
state income taxes otherwise payable.
The trust units may constitute real property or an interest in real property under the
inheritance, estate and probate laws of Pennsylvania.
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ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended, regulates pension,
profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards
for persons who are fiduciaries of those plans. In addition, the Internal Revenue Code provides
similar requirements and standards which are applicable to qualified plans, which include these
types of plans, and to individual retirement accounts, whether or not subject to ERISA.
A fiduciary of a qualified plan should carefully consider fiduciary standards under ERISA
regarding the qualified plans particular circumstances before authorizing an investment in trust
units. A fiduciary should consider:
| whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA; | ||
| whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and | ||
| whether the investment is in accordance with the documents and instruments governing the qualified plan as required by Section 404(a)(1)(D) of ERISA. |
A fiduciary should also consider whether an investment in common units might result in direct
or indirect nonexempt prohibited transactions under Section 406 of ERISA and Internal Revenue Code
Section 4975. In deciding whether an investment involves a prohibited transaction, a fiduciary must
determine whether there are plan assets in the transaction. The Department of Labor has published
final regulations concerning whether or not a qualified plans assets would be deemed to include an
interest in the underlying assets of an entity for purposes of the reporting, disclosure and
fiduciary responsibility provisions of ERISA and analogous provisions of the Internal Revenue Code.
These regulations provide that the underlying assets of an entity will not be considered plan
assets if the equity interests in the entity are a publicly offered security. ECA expects that at
the time of the sale of the trust units in this offering, they will be publicly offered securities.
Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt
prohibited transaction under the general requirements of ERISA Section 406 and Internal Revenue
Code Section 4975.
The prohibited transaction rules are complex, and persons involved in prohibited transactions
are subject to penalties. For that reason, potential qualified plan investors should consult with
their counsel to determine the consequences under ERISA and the Internal Revenue Code of their
acquisition and ownership of trust units.
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SELLING TRUST UNITHOLDERS
This
prospectus covers the offering for resale or transfer of up to 3,001,733 common
units by ECA. ECA acquired its units on July 7, 2010 at the
formation and initial public offering of the trust. The trust is registering the common units
described below pursuant to a registration rights agreement entered
into by the Trust, ECA and certain affiliates in connection with such transaction.
No offer or sale may
be made except by ECA. ECA may sell all, some or none of the common units
covered by this prospectus. Please read Underwriting and Plan of Distribution. ECA will bear all costs, fees and
expenses incurred in connection with the registration of the common units offered by this
prospectus. Brokerage commissions and similar selling expenses, if any, attributable to the sale of
common units will be borne by the selling trust unitholder.
No such sales may occur unless this prospectus has been declared effective by the SEC, and
remains effective at the time such selling trust unitholder offer or sells such common units. We
are required to update this prospectus to reflect material developments in our business, financial
position and results of operations.
The following table provides information regarding the selling trust unitholders ownership of
the trust units.
Number of | Ownership of Trust | |||||||||||||||
Ownership of Trust Units Before Offering | Common Units | Units following | ||||||||||||||
Selling Trust Unitholder | Number | Percentage | Being Offered | this Offering | ||||||||||||
Energy Corporation
of America |
7,402,983 | 42.1 | % | 3,001,733 | (1) | 4,401,250 | (2) |
(1) | In connection with this offering, 116,010 common units are being conveyed by ECA to certain eligible employees. Please read Underwriting Employee Incentive Units. | |
(2) | Such units are subordinated units, which will automatically convert into common units on a one-for-one basis and ECAs right to receive incentive distributions and to recoup the Reimbursement Amount will terminate, at the end of the fourth full calendar quarter following ECAs satisfaction of its drilling obligation to the trust. | |
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UNDERWRITING
AND PLAN OF DISTRIBUTION
Subject to the terms and conditions in an underwriting agreement dated March , 2011, the
underwriters named below, for whom Citigroup Global Markets Inc. is acting as representative, have
severally agreed to purchase from ECA the
number of
common units set forth opposite their names:
Number of | ||||
Name of Underwriter | Common Units | |||
Citigroup Global Markets Inc. |
||||
Oppenheimer & Co. Inc. |
||||
RBC Capital
Markets, LLC |
||||
Total |
2,525,000 |
The underwriting agreement provides that the obligations of the underwriters to purchase and
accept delivery of the common units offered by this prospectus are subject to the satisfaction of
the conditions contained in the underwriting agreement, including:
| the representations and warranties made by ECA to the underwriters are true; | ||
| there is no material adverse change in the financial market; and | ||
| ECA and the Trust deliver customary closing documents and legal opinions to the underwriters. | ||
The underwriters are obligated to purchase and accept delivery of all of the trust units
offered by this prospectus, if any of the units are purchased, other than those covered by the
option to purchase additional common units described below.
The underwriters propose to offer the common units directly to the public at the public
offering price indicated on the cover page of this prospectus and to various dealers at that price
less a concession not in excess of $ per unit. If all of the common units are not sold at
the public offering price, the underwriters may change the public offering price and other selling
terms. The common units are offered by the underwriters as stated in this prospectus, subject to
receipt and acceptance by them. The underwriters reserve the right to reject an order for the
purchase of the common units in whole or in part.
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OPTION TO PURCHASE ADDITIONAL COMMON UNITS
ECA has granted the underwriters an option, exercisable for 30 days after the date of
this prospectus, to purchase from time to time up to an aggregate of
360,723 additional common
units to cover over-allotments, if any, at the public offering price less the underwriting
discounts and commissions set forth on the cover page of this
prospectus. If the underwriters exercise this option, each underwriter, subject to
certain conditions, will become obligated to purchase its pro rata portion of these additional
units based on the underwriters percentage purchase commitment in this offering as indicated in
the table above. The underwriters may exercise the option to purchase additional common units only
to cover over-allotments made in connection with the sale of the common units offered in this
offering.
DISCOUNTS AND EXPENSES
The following table shows the amount
per unit and total underwriting discounts ECA will pay to the underwriters (dollars in thousands, except per unit). The amounts are
shown assuming both no exercise and full exercise of the underwriters option to purchase
additional common units.
Total without | Total with | |||||||||||
Over- | Over- | |||||||||||
Allotment | Allotment | |||||||||||
Per Unit | Exercise | Exercise | ||||||||||
Public
offering price |
$ | |||||||||||
Underwriting discount and commissions |
$ | |||||||||||
Proceeds to
ECA (before expenses) |
$ |
INDEMNIFICATION
ECA and the Trust
have agreed to indemnify the underwriters and persons who control the
underwriters against certain liabilities that may arise in connection with this offering, including
liabilities under the Securities Act of 1933 and liabilities arising from breaches of
representations and warranties contained in the underwriting agreement.
LOCK-UP AGREEMENTS
Subject to specified exceptions
(including the conveyence of the 116,010 common units to be conveyed
to certain eligible employees)
ECA and certain affiliates have agreed
with the underwriters, for a period of 60 days
after the date of this prospectus, without the prior written consent of Citigroup Global Markets
Inc.:
| not to offer, sell, contract to sell, announce the intention to sell or pledge any of the trust units; | ||
| not to grant or sell any option or contract to purchase any of the trust units; | ||
| not to enter into any swap or other agreement that transfers any of the economic consequences of ownership of or otherwise transfer or dispose of, directly or indirectly, any of the trust units; and | ||
| not to enter into any hedging, collar or other transaction or arrangement that is designed or reasonably expected to lead to or result in a transfer, in whole or in part, of any of the economic consequences of ownership of the trust units, whether or not such transfer would be for any consideration. | ||
These agreements also prohibit ECA from entering into any of the foregoing transactions with
respect to any securities that are convertible into or exchangeable for the trust units.
Citigroup
Global Markets Inc. may, in its discretion and at any time without notice, release
all or any portion of the securities subject to these agreements. Citigroup Global Markets Inc.
does not have any present intent or any understanding to release all or any portion of the
securities subject to these agreements.
The
60-day period described in the preceding paragraphs will be extended if:
| during the last 17 days of the 60-day period, the trust issues an earnings release or announces material news or a material event relating to the trust occurs; or | ||
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| prior to the expiration of the 60-day period, the trust announces that it will release earnings results during the 16-day period beginning on the last day of the 60-day period, in which case the restrictions described in the preceding paragraphs will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release, the announcement of the material news or the occurrence of the material event. | ||
STABILIZATION
Until this offering is completed, rules of the SEC may limit the ability of the underwriters
and various selling group members to bid for and purchase the common units. As an exception to
these rules, the underwriters may engage in activities that stabilize, maintain or otherwise affect
the price of the common units, including:
| short sales, | ||
| syndicate covering transactions, | ||
| imposition of penalty bids, and | ||
| purchases to cover positions created by short sales. | ||
Stabilizing transactions consist of bids or purchases made for the purpose of preventing or
retarding a decline in the market price of the common units while this offering is in progress.
Stabilizing transactions may include making short sales of common units, which involve the sale by
the underwriters of a greater number of common units than it is required to purchase in this
offering and purchasing common units from ECA or in the open market to cover positions created by
short sales. Short sales may be covered shorts, which are short positions in an amount not
greater than the underwriters option to purchase additional common units referred to above, or may
be naked shorts, which are short positions in excess of that amount.
Each underwriter may close out any covered short position either by exercising its option to
purchase additional common units, in whole or in part, or by purchasing common units in the open
market. In making this determination, each underwriter will consider, among other things, the price
of common units available for purchase in the open market compared to the price at which the
underwriter may purchase common units pursuant to the option to purchase additional common units.
A naked short position is more likely to be created if the underwriters are concerned that
there may be downward pressure on the price of the common units in the open market that could
adversely affect investors who purchased in this offering. To the extent that the underwriters
create a naked short position, they will purchase common units in the open market to cover the
position.
The underwriters also may impose a penalty bid on selling group members. This means that if
the underwriters purchase common units in the open market in stabilizing transactions or to cover
short sales, the underwriters can require the selling group members that sold those common units as
part of this offering to repay the selling concession received by them.
As a result of these activities, the price of the common units may be higher than the price
that otherwise might exist in the open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The underwriters may carry out these transactions
on the New York Stock Exchange or otherwise.
CONFLICTS/AFFILIATES
Certain of the underwriters and their affiliates may provide in the future investment banking,
financial advisory or other financial services for ECA and its affiliates, for which they may
receive advisory or transaction fees, as applicable, plus out-of-pocket expenses, of the nature and
in amounts customary in the industry for these financial services.
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EMPLOYEE INCENTIVE UNITS
ECA will convey 116,010 common units (Employee Units) to
certain of its eligible employees as incentive compensation. ECA expects to
deliver these units on or about 60 days following the closing of this offering. The Employee
Units are included in this registration statement of which this
prospectus is a part. The underwriters have not agreed and will not
be obligated to purchase any Employee Units.
DISCRETIONARY ACCOUNTS
The underwriters may confirm sales of the common units offered by this prospectus to accounts
over which they exercise discretionary authority but do not expect those sales to exceed 5% of the
total common units offered by this prospectus.
LISTING
The
common units are listed on the New York Stock Exchange under the symbol ECT.
ELECTRONIC PROSPECTUS
A prospectus in electronic format may be available on the Internet sites or through other
online services maintained by one or more of the underwriters and selling group members
participating in this offering, or by their affiliates. In those cases, prospective investors may
view offering terms online and, depending upon the underwriter or the selling group member,
prospective investors may be allowed to place orders online. The underwriters may agree with ECA to
allocate a specific number of common units for sale to online brokerage account holders. Any such
allocation for online distributions will be made by the underwriters on the same basis as other
allocations.
Other than the prospectus in electronic format, the information on any underwriters or any
selling group members website and any information contained in any other website maintained by the
underwriters or any selling group member is not part of this prospectus or the registration
statement of which this prospectus forms a part, has not been approved or endorsed by ECA or any
underwriters or any selling group member in its capacity as underwriter or selling group member and
should not be relied upon by investors.
FINRA RULES
Because the Financial Industry Regulatory Authority, or the FINRA is expected to view the
common units offered hereby as interests in a direct participation program, this offering is being
made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the
common units should be judged similarly to the suitability with respect to other securities that
are listed for trading on a national securities exchange.
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LEGAL MATTERS
Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal
opinion as to the validity of the trust units. Vinson & Elkins L.L.P., Houston, Texas, counsel to
ECA, will give opinions as to certain other matters relating to the offering, including the tax
opinion described in the section of this prospectus captioned Federal income tax considerations.
Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
Certain information appearing in this prospectus regarding the December 31, 2010 estimated
quantities of reserves of the Royalties owned by the trust, the future net cash flows from those
reserves and their present value is based on estimates of the reserves and present values prepared
by or derived from estimates prepared by Ryder Scott Company, L.P., independent petroleum
engineers.
The statement of assets, liabilities and trust corpus as of December 31, 2010 and the related
statements of distributable income and trust corpus for the period from inception (March 19, 2010)
to December 31, 2010 of ECA Marcellus Trust I, appearing in this registration statement and
prospectus have been audited by Ernst & Young LLP, independent registered public accounting firm,
as set forth in their report thereon appearing elsewhere herein, and is included in reliance upon
such report given on the authority of such firm as experts in accounting and auditing.
WHERE YOU CAN FIND MORE INFORMATION
The Trust has filed with the SEC a registration statement on Form S-1 regarding the
common units. This prospectus does not contain all of the information found in the registration
statement. For further information regarding the trust and the common units offered by this
prospectus, you may desire to review the full registration statement, including its exhibits and
schedules, filed under the Securities Act. The registration statement of which this prospectus
forms a part, including its exhibits and schedules, may be inspected and copied at the public
reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549.
Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the
public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C.
20549. You may obtain information on the operation of the public reference room by calling the SEC
at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The Trusts
registration statement, of which this prospectus constitutes a part, can be downloaded
from the SECs web site.
We intend to furnish the trusts unitholders annual reports containing our audited
consolidated financial statements and to furnish or make available to the trusts unitholders
quarterly reports containing the trusts unaudited interim financial information for the first
three fiscal quarters of each of our fiscal years.
The SEC allows the trust to incorporate by reference the information we have filed with the
SEC. This means that we can disclose important information to you without actually including the
specific information in this prospectus by referring you to other documents filed separately with
the SEC. The information incorporated by reference is an important part of this prospectus.
The trust incorporates by reference in this prospectus the following documents that it has
previously filed with the SEC:
| The trusts annual report on Form 10-K for the year ended December 31, 2010, as filed with the SEC on February 28, 2011; |
This report contains important information about the trust, its financial condition and our
results of operations.
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You may request a copy of any document incorporated by reference in this prospectus and any
exhibit specifically incorporated by reference in those documents, at no cost, by writing or
telephoning us at the following address or phone number:
ECA Marcellus Trust I
C/O The Bank of New York Mellon Trust Company, N.A., as Trustee
919 Congress Avenue
Austin, Texas 78701
1-800-852-1422
C/O The Bank of New York Mellon Trust Company, N.A., as Trustee
919 Congress Avenue
Austin, Texas 78701
1-800-852-1422
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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST
TERMS RELATED TO THE TRUST
In this prospectus the following terms have the meanings specified below.
AMI The area of mutual interest, or AMI, consists of the Marcellus Shale formation in
approximately 121 square miles of property located in Greene County, Pennsylvania in which ECA had
leased approximately 9,300 acres and owned substantially all of the working interests at the date
of formation of the trust. ECA is obligated to drill the 52 development wells from drill sites on
approximately 9,300 leased acres in the AMI. Until ECA has satisfied its drilling obligation, it
will not be permitted to drill and complete any well in the Marcellus Shale formation within the
AMI for its own account.
Bbl One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to
crude oil, condensate or natural gas liquids.
Bcf One billion cubic feet of natural gas.
Bcfe One billion cubic feet of natural gas equivalent, with one barrel of crude oil being
equivalent to six Mcf.
Btu A British Thermal Unit, a common unit of energy measurement.
ECAs retained interest ECAs retained interest in 10% of the proceeds from the sale of
production from the 14 producing Marcellus Shale natural gas wells located in Greene County,
Pennsylvania as well as ECAs retained interest in 50% of the proceeds from the sale of production
from the PUD Wells to be drilled in the AMI.
Estimated future net revenues Also referred to as estimated future net cash flows. The
result of applying current prices of natural gas to estimated future production from natural gas
proved reserves, reduced by estimated future expenditures, based on current costs to be incurred,
in developing and producing the proved reserves, excluding overhead.
Farmout agreement A farmout agreement is typically an agreement under which a lessee under
an oil and gas lease agrees to grant to another party the right to drill wells on the tract covered
by such lease and to earn certain acreage for drilling such wells.
Fractional well The fraction (either greater than one or less than one) of a well obtained
by dividing the horizontal lateral (measured from the midpoint of the curve) of such well by 2,500
feet (subject to a maximum of 3,500 feet).
Initial Prospectus The prospectus dated July 1, 2010 and filed with the SEC pursuant to
Rule 424(b) on July 1, 2010 relating to the initial public
offering of the trust units.
MBbl One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf One thousand cubic feet of natural gas.
Mcfe One thousand cubic feet of natural gas equivalent, with one barrel of crude oil being
equivalent to six Mcf.
MMBtu One million British Thermal Units.
MMcf One million cubic feet of natural gas.
MMcfe One million cubic feet of natural gas equivalent, with one barrel of crude oil being
equivalent to six Mcf.
Net Profits Interest A nonoperating interest that creates a share in gross production from
an operating or working interest in oil and natural gas properties. The share is measured by net
profits from the sale of production after deducting costs associated with that production.
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PDP Royalty Interest Royalty interests entitling the trust to receive an aggregate of 90%
of the proceeds (exclusive of any production or development costs but after deducting
post-production costs and any applicable taxes) from the sale of production of natural gas
attributable to, as of April 30, 2010, ECAs working interest in the eight horizontal wells
producing from the Marcellus Shale formation together with six additional wells that were
undergoing completion operations and the last of which was turned online on August 27, 2010
(Producing Wells), for 20 years and 45% of such proceeds thereafter (pending a sale thereof by
the trust).
Private Investors the persons described as the Private Investors in the Initial
Prospectus.
Proved developed reserves Reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved reserves Under SEC rules for fiscal years ending on or after December 31, 2009,
proved reserves are defined as:
Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
Proved undeveloped reserves Proved reserves that are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major expenditure is required
for recompletion.
PUD Royalty Interest Royalty interests entitling the trust to receive an aggregate of 50%
of the proceeds (net of post-production costs and any applicable taxes) from the sale of production
of natural gas attributable to ECAs interest in 52 horizontal Marcellus Shale natural gas wells to
be drilled in the AMI for 20 years and 25% of such proceeds thereafter (pending a sale thereof by
the trust).
Tcf One trillion standard cubic feet of natural gas.
Working interest The right granted to the lessee of a property to explore for and to
produce and own oil, gas, or other minerals. The working interest owners bear the exploration,
development, and operating costs on either a cash, penalty, or carried basis.
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INDEX TO FINANCIAL STATEMENTS
TABLE OF CONTENTS
F-2 | ||||
F-3 | ||||
F-4 | ||||
F-5 | ||||
F-6 | ||||
F-10 |
F-1
Table of Contents
ECA MARCELLUS TRUST I
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To The Bank of New York Mellon Trust Company, N.A., as Trustee of
ECA Marcellus Trust I
ECA Marcellus Trust I
We have audited the accompanying statement of assets, liabilities, and trust corpus of ECA
Marcellus Trust I (the Trust) as of December 31, 2010, and the related statements of distributable
income and trust corpus for the period from inception (March 19, 2010) to December 31, 2010. These
financial statements are the responsibility of the Trustee. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. We were not engaged to perform an audit of the Trusts internal control over
financial reporting. Our audit included consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for
the purpose of expressing an opinion on the effectiveness of the Trusts internal control over
financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by the Trustee, and
evaluating the overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
As described in Note 3, the financial statements have been prepared on a modified cash basis
of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted
accounting principles.
In our opinion, the statements referred to above present fairly, in all material respects, the
financial position of ECA Marcellus Trust I as of December 31, 2010 and its distributable income
for the period from inception (March 19, 2010) to December 31, 2010, on the basis of accounting
described in Note 3.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 28, 2011
February 28, 2011
F-2
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ECA MARCELLUS TRUST I
STATEMENT OF ASSETS, LIABILITIES AND TRUST CORPUS
As of December 31, 2010
ASSETS: |
||||
Cash |
$ | 398,324 | ||
Royalty income receivable |
6,885,434 | |||
Hedge proceeds receivable |
2,032,620 | |||
Floor price contracts |
4,858,920 | |||
Royalty interest in gas properties |
352,100,000 | |||
Accumulated amortization |
(14,854,467 | ) | ||
Net royalty interest in gas properties |
337,245,533 | |||
Total Assets |
$ | 351,420,831 | ||
LIABILITIES AND TRUST CORPUS: |
||||
Liabilities: |
||||
Floor premiums payable |
$ | 4,957,920 | ||
Distributions payable to unitholders |
8,809,013 | |||
Incentive distribution payable to ECA |
| |||
Floor costs payable to ECA as: |
||||
Premium |
| |||
Interest |
| |||
Trust corpus; 13,203,750 common units and 4,401,250
subordinated units authorized and outstanding |
337,653,898 | |||
Total Liabilities and Trust Corpus |
$ | 351,420,831 | ||
See notes to the financial statements.
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ECA MARCELLUS TRUST I
STATEMENT OF DISTRIBUTABLE INCOME
FOR THE PERIODS ENDED DECEMBER 31, 2010
(Audited) | (Unaudited) | |||||||
From Inception | Three Months Ended | |||||||
Royalty income |
$ | 16,925,157 | $ | 6,885,434 | ||||
Hedge proceeds |
5,746,831 | 2,302,920 | ||||||
Net proceeds to Trust |
$ | 22,671,988 | $ | 9,188,354 | ||||
General and administrative expense |
(1,038,388 | ) | (379,750 | ) | ||||
Interest income |
409 | 409 | ||||||
Income available for distribution prior to cash reserves and incentive calculation |
$ | 21,634,009 | $ | 8,809,013 | ||||
Cash reserves (withheld) released by Trustee |
(500,000 | ) | | |||||
Income available for distribution prior to incentive calculation |
$ | 21,134,009 | $ | 8,809,013 | ||||
Less: |
||||||||
Incentive distribution to ECA |
58,688 | | ||||||
Floor cost reimbursement distribution to ECA as: |
||||||||
Premium |
| | ||||||
Interest |
58,688 | | ||||||
Distriibutable income available to unitholders |
$ | 21,016,633 | $ | 8,809,013 | ||||
Distributable income per unit
(13,203,750 common units and 4,401,250 subordinated units authorized and outstanding) |
$ | 1.193 | $ | 0.500 | ||||
See notes to the financial statements.
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ECA MARCELLUS TRUST I
STATEMENT OF TRUST CORPUS
AS OF DECEMBER 31, 2010
Trust Corpus, Beginning of Period |
$ | 10 | ||
Issuance of trust units |
352,100,000 | |||
Cash reserves |
500,000 | |||
Distribution income |
21,016,633 | |||
Distributions paid or payable to unitholders |
(21,009,278 | ) | ||
Amortization of royalty interest in gas properties |
(14,854,467 | ) | ||
Amortization of floor contracts |
(99,000 | ) | ||
Trust Corpus, End of Period |
$ | 337,653,898 | ||
See notes to the financial statements.
F-5
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ECA
MARCELLUS TRUST I
NOTES TO FINANCIAL STATEMENTS
FOR THE PERIODS ENDED DECEMBER 31, 2010
FOR THE PERIODS ENDED DECEMBER 31, 2010
NOTE 1. Organization of the Trust
ECA Marcellus Trust I is a Delaware statutory trust formed in March 2010 by Energy Corporation
of America (ECA) to own royalty interests in fourteen producing horizontal natural gas wells
producing from the Marcellus Shale formation, all of which are online and are located in Greene
County, Pennsylvania (the Producing Wells) and royalty interests in 52 horizontal natural gas
development wells to be drilled to the Marcellus Shale formation (the PUD Wells) within the Area
of Mutual Interest, or AMI, comprised of approximately 9,300 acres held by ECA, of which it owns
substantially all of the working interests, in Greene County, Pennsylvania. The effective date of
the Trust was April 1, 2010; consequently, the Trust received the proceeds of production
attributable to the PDP Royalty Interest from that date even though the PDP Royalty Interest was
not conveyed to the Trust until the closing of the initial public offering on July 7, 2010. The
total number of units the Trust is authorized to issue is 17,605,000 units, of which 13,203,750 are
common units and 4,401,250 are subordinated units. The royalty interests were conveyed from ECAs
working interest in the Producing Wells and the PUD Wells limited to the Marcellus Shale formation
(the Underlying Properties). The royalty interest in the Producing Wells (the PDP Royalty
Interest) entitles the Trust to receive 90% of the proceeds (exclusive of any production or
development costs but after deducting post-production costs and any applicable taxes) from the sale
of production of natural gas attributable to ECAs interest in the Producing Wells. The royalty
interest in the PUD Wells (the PUD Royalty Interest and collectively with the PDP Royalty
Interest, the Royalty Interests) entitles the Trust to receive 50% of the proceeds (exclusive of
any production or development costs but after deducting post-production costs and any applicable
taxes) from the sale of production of natural gas attributable to ECAs interest in the PUD Wells.
Approximately 50% of the estimated natural gas production attributable to the Trusts royalty
interests has been hedged with a combination of floors and swaps through March 31, 2014. The floor
price contracts were transferred to the Trust by ECA, while ECA entered into a back-to-back swap
agreement with the Trust to provide the Trust with the benefit of swap contracts entered into
between ECA and third parties. ECA will be entitled to recoup the costs of establishing the floor
price contracts only if and to the extent cash available for distribution by the Trust exceeds
certain levels.
ECA is obligated to drill all of the PUD Wells by March 31, 2013; however, in the event of
delays, ECA will have until March 31, 2014 to fulfill its drilling obligation. ECA has granted to
the Trust a lien (the Drilling Support Lien) on ECAs interest in the Marcellus Shale formation
in the AMI (except the Producing Wells and any other wells which are already producing and not
subject to the Royalty Interests) in order to secure the estimated amount of the drilling costs for
the Trusts interests in the PUD Wells. The amount obtained by the Trust pursuant to the Drilling
Support Lien may not exceed $91 million. As ECA fulfills its drilling obligation over time, the
total dollar amount that may be recovered will be proportionately reduced and the drilled PUD Wells
will be released from the lien.
The Trust is not responsible for any costs related to the drilling of development wells or any
other development or operating costs. The Trusts cash receipts in respect of the royalties will be
determined after deducting post-production costs and any applicable taxes associated with the PDP
and PUD Royalty Interests, and the Trusts cash available for distribution will include cash
receipts from its hedging contracts and will be reduced by Trust administrative expenses and
expenses incurred as a result of being a publicly traded entity. Post-production costs will
generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and
market the natural gas produced. Any charge payable to ECA for such post-production costs on its
Greene County Gathering System will be limited to $0.52 per MMBtu gathered until ECA has fulfilled
its drilling obligation (the Post-Production Services Fee); thereafter, ECA may increase the
Post-Production Services Fee to the extent necessary to recover certain capital expenditures in the
Greene County Gathering System. Generally, the percentage of production proceeds to be received by
the Trust with respect to a well will equal the product of (i) the percentage of proceeds to which
the Trust is entitled under the terms of the conveyances (90% for the Producing Wells and 50% for
the PUD Wells) multiplied by (ii) ECAs net revenue interest in the well. ECA on average owns an
81.53% net revenue interest in the Producing Wells. Therefore, the Trust will be entitled to
receive on average 73.37% of the proceeds of production from the Producing Wells. With respect to a
PUD Well, the conveyance related to the PUD
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Royalty Interest provides that the proceeds from the PUD Wells will be calculated on the basis
that the underlying PUD Wells are burdened only by interests that in total would not exceed 12.5%
of the revenues from such properties, regardless of whether the royalty interest owners are
actually entitled to a greater percentage of revenues from such properties. As the applicable net
revenue interest of a well is calculated by multiplying ECAs percentage working interest in such
well by the unburdened interest percentage (87.5%), assuming ECA owns a 100% working interest in a
PUD Well, such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust would
be entitled to 43.75% of the production proceeds from such well. To the extent ECAs working
interest in a PUD well is less than 100%, the Trusts share of proceeds would be proportionately
reduced. Pursuant to the Development Agreement, however, ECA will only satisfy its drilling
obligation when it has drilled 52 equivalent wells. Therefore, any reduction in production proceeds
attributable to a PUD Well caused by ECA having less than a 100% working interest in the well will
be offset by the requirement to drill additional wells to achieve a total of 52 equivalent wells.
The Trust will make quarterly cash distributions of substantially all of its cash receipts,
after deducting Trust administrative expenses and the costs incurred as a result of being a
publicly traded entity, on or about 60 days following the completion of each quarter through (and
including) the quarter ending March 31, 2030 (the Termination Date). The first quarterly
distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The Trust
will begin to liquidate on the Termination Date and will soon thereafter wind up its affairs and
terminate. At the Termination Date, 50% of each of the PDP Royalty Interest and the PUD Royalty
Interest will revert automatically to ECA. The remaining 50% of each of the PDP Royalty Interest
and the PUD Royalty Interest will be sold, and the net proceeds will be distributed pro rata to the
unitholders soon after the Termination Date. ECA will have a first right of refusal to purchase the
remaining 50% of the royalty interests at the Termination Date.
In order to provide support for cash distributions on the common units, ECA has agreed to
subordinate 4,401,250 of the trust units it owns, which constitute 25% of the outstanding trust
units. The subordinated units are entitled to receive pro rata distributions from the Trust each
quarter if and to the extent there is sufficient cash to provide a cash distribution on the common
units which is at least equal to the applicable quarterly subordination threshold. However, if
there is not sufficient cash to fund such a distribution on all trust units, the distribution with
respect to the subordinated units will be reduced or eliminated for such quarter in order to make a
distribution, to the extent possible, of up to the subordination threshold amount on the common
units. 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 is 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.
ECAs right to receive the incentive distributions will terminate upon the expiration of the
subordination period.
ECA incurred costs of approximately $5.0 million for floor price contracts that were
transferred to the Trust. ECA is 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
ECAs right to receive incentive distributions and to recoup the reimbursement amount will
terminate, at the end of the fourth full calendar quarter following ECAs satisfaction of its
drilling obligation to the Trust. Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the floor price contracts transferred to the Trust. ECA currently expects that
it will complete its drilling obligation on or before March 31, 2013 and that, accordingly, the
subordinated units will convert into common units on or before March 31, 2014. In the event of
delays, it will have until March 31, 2014 under its contractual obligation to drill all the PUD
Wells, in which event the subordinated units would convert into common units on or before March 31,
2015. The period during which the subordinated units are outstanding is referred to as the
subordination period.
The business and affairs of the Trust are managed by The Bank of New York Mellon Trust
Company, N.A. as Trustee. Although ECA operates 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.
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NOTE 2. Basis of Presentation
The preparation of financial statements requires the Trust to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenue and
expenses during the reporting period. Without limiting the foregoing statement, the information
furnished is based upon certain estimates of the revenues attributable to the Trust from natural
gas production for the three month and inception to date periods ended December 31, 2010 and is
therefore subject to adjustment in future periods to reflect actual production for the periods
presented.
NOTE 3. Significant Accounting Policies
The accompanying audited financial information has been prepared by the Trustee in accordance
with the instructions to Form 10-K. The financial statements of the Trust differ from financial
statements prepared in accordance with generally accepted accounting principles in the United
States of America (GAAP) because certain cash reserves may be established for contingencies,
which would not be accrued in financial statements prepared in accordance with GAAP. Amortization
of expired floor price contract premiums does not reduce Distributable Income, rather it is charged
directly to Trust Corpus. Amortization of the investment in overriding royalty interests calculated
on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of
accounting other than GAAP corresponds to the accounting permitted for royalty Trusts by the U.S.
Securities and Exchange Commission as specified by FASB ASC Topic 932 Extractive ActivitiesOil
and Gas: Financial Statements of Royalty Trusts. Income determined on the basis of GAAP would
include all expenses incurred for the period presented. However, the Trust serves as a pass-through
entity, with expenses for depreciation, depletion, and amortization, interest and income taxes
being based on the status and elections of the Trust unitholders. General and administrative
expenses, production taxes or any other allowable costs are charged to the Trust only when cash has
been paid for those expenses. In addition, the royalty interest is not burdened by field and lease
operating expenses. Thus, the statement purports to show distributable income, defined as income of
the Trust available for distribution to the Trust unitholders before application of those
additional expenses, if any, for depreciation, depletion, and amortization, interest and income
taxes. The revenues are reflected net of existing royalties and overriding royalties and have been
reduced by gathering/post-production expenses.
Cash:
Cash consists of highly liquid instruments with maturities at the time of acquisition of three
months or less.
Use of Estimates in the Preparation of Financial Statements:
The preparation of financial statements requires the Trust to make estimates and assumptions
that affect the reported amounts of assets and liabilities and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expenses:
The Trust serves as a pass-through entity, with items of depletion, interest income and
expense, and income tax attributes being based upon the status and election of the unitholders.
Thus, the Statements of Distributable Income purport to show Income available for distribution
before application of those unitholders additional expenses, if any, for depletion, interest
income and expense, and income taxes.
The Trust uses the accrual basis to recognize revenue, with royalty income recorded as
reserves are extracted from the Underlying Properties and sold. Expenses are recognized when paid.
Royalty Interest in Gas Properties:
The Royalty Interests in gas properties are assessed to determine whether their net
capitalized cost is impaired, whenever events or changes in circumstances indicate that its
carrying amount may not be recoverable, pursuant to Accounting Standards Codification 360,
Property, Plant and Equipment (ASC 360). The Trust will determine if a writedown is necessary to
its investment in the Royalty Interests in gas properties to the extent that total capitalized
costs, less accumulated amortization, exceed undiscounted future net revenues attributable to
proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the
extent that the net capitalized costs exceed the fair value of the investment in net profits
interests attributable to proved gas reserves of the Underlying
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Properties. Any such writedown would not reduce Distributable Income, although it would reduce
Trust Corpus. No impairment in the Underlying Properties was recognized during the periods ended
December 31, 2010. Significant dispositions or abandonment of the Underlying Properties are charged
to Royalty Interests and the Trust Corpus.
Amortization of the Royalty Interests in gas properties is calculated on a units-of-production
basis, whereby the Trusts cost basis in the properties is divided by Trust total proved reserves
to derive an amortization rate per reserve unit. Such amortization does not reduce Distributable
Income, rather it is charged directly to Trust Corpus. Revisions to estimated future
units-of-production are treated on a prospective basis beginning on the date significant revisions
are known.
The conveyance of the Royalty Interests to the Trust was accounted for as a purchase
transaction. The $352,100,000 reflected in the Statements of Assets, Liabilities and Trust Corpus
as Royalty Interests in Gas Properties represents 17,605,000 Trust Units valued at $20.00 per unit.
The carrying value of the Trusts investment in the Royalty Interests is not necessarily indicative
of the fair value of such Royalty Interests.
Accrued Interest Payable:
Accrued interest payable to ECA by the Trust is calculated at 10% per annum on the outstanding
balance of the floor contract premiums payable, but is not recorded by the Trust until paid. As of
December 31, 2010, the amount of unrecorded accrued interest payable to ECA was $313,156.
NOTE 4. Commodity Hedges
The Trust is exposed to risk fluctuations in energy prices in the normal course of operations.
ECA conveyed to the Trust natural gas derivative floor price contracts and entered into a
back-to-back swap agreement with the Trust which conveyed the benefit of certain swap agreements
which ECA had previously entered into with third parties. The volumes covered by these agreements
equate to approximately 50% of the estimated natural gas to be produced by the Trust properties
through March 31, 2014. The swap contracts relate to approximately 7,500 MMBtu per day at a
weighted average price of $6.78 per MMBtu for the period from April 1, 2010 through June 30, 2012.
The price of the floor hedging contracts is $5.00 per MMBtu on a total volume of 11,268,000 MMBtu
for the period from October 1, 2010 through March 31, 2014. The Trust uses the cash method to
account for commodity contracts. Under this method, gains or losses associated with the contracts
are recognized at the time the hedged production occurs. Hedge proceeds realized for the quarter
and inception to date for the periods ended December 31, 2010 totalled $2,302,920 and $5,746,831,
respectively. The fair market values of the commodity contracts are not included in the
accompanying financial statements, as the statements are presented on a modified cash basis of
accounting.
NOTE 5. Income Taxes
The Trust is a Delaware statutory trust, which is taxed as a partnership for federal and state
income taxes. Accordingly, no provision for federal or state income taxes has been made.
NOTE 6. Related Party Transactions
Trustee Administrative Fee:
Under the terms of the trust agreement, the Trust pays an annual administrative fee of
$150,000 to the Trustee, which may be adjusted beginning on the fifth anniversary of the Trust as
provided in the trust agreement. These costs, as well as those to be paid to ECA pursuant to the
Administrative Services Agreement referred to below, will be deducted by the Trust in the period
paid. The Trustee waived its administrative fee for the quarter ended June 30, 2010, but does not
intend to waive the fee for any other quarter.
Administrative Services Fee:
The Trust entered into an Administrative 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 Royalties. The
annual fee of $60,000 is payable in equal quarterly installments. After the completion of ECAs
drilling obligation, under certain circumstances, ECA and the Trustee
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each may terminate the Administrative Services Agreement at any time following delivery of
notice no less than 90 days prior to the date of termination. ECA waived its administrative
services fee for the quarter ended June 30, 2010, but does not intend to waive the fee for any
other quarter.
Drilling Support Lien:
As described in Note 1, ECA has granted to the Trust the Drilling Support Lien on ECAs
interest in the Marcellus Shale formation in the AMI (except the Producing Wells and any other
wells which are already producing and not subject to the Royalty Interests) in order to secure the
estimated amount of the drilling costs for the Trusts interests in the PUD Wells. The Drilling
Support Lien is limited to $91 million, and as ECA fulfills its drilling obligation over time, the
total dollar amount is to be proportionately reduced. As of December 31, 2010, ECA had received a
partial release of the Drilling Support Lien in the amount of approximately $16.9 million.
NOTE 7. Subsequent Events
As of February 23, 2011, two additional PUD wells had been brought online by ECA that were
producing 2,653 Mcf per day net to the Trusts interest. Also, twelve additional PUD wells have
been drilled and are undergoing or awaiting completion operations.
Supplemental Reserve Information (Unaudited):
Information regarding estimates of the proved gas reserves attributable to the Trust are based
on reports prepared by independent petroleum engineering consultants. Such estimates were prepared
in accordance with guidelines established by the Securities and Exchange Commission. Accordingly,
the estimates were based on existing economic and operating conditions. Numerous uncertainties are
inherent in estimating reserve volumes and values and such estimates are subject to change as
additional information becomes available.
The reserves actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.
The standardized measure of discounted future net cash flows was determined based on reserve
estimates prepared by the independent petroleum engineering consultants, Ryder Scott.
The following table reconciles the estimated quantities of the proved natural gas reserves
attributable to the Trusts interest from inception of the Trust to December 31, 2010:
Natural Gas | ||||
(Mmcf) | ||||
Proved reserves: |
||||
Balance at Inception |
108,640 | |||
Revisions of previous estimates |
(1,608 | ) | ||
Production |
(4,583 | ) | ||
December 31, 2010 |
102,449 | |||
Proved developed reserves: |
||||
December 31, 2010 |
42,487 | |||
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
The standardized measure of discounted future net cash flows relating to proved oil and gas
reserves and the changes in standardized measure of discounted future net cash flows relating to
proved oil and gas reserves were prepared in accordance with the provisions of FASB ASC topic
Extractive ActivitiesOil and Gas. Future cash inflows were computed by applying prices at year
end to estimated future production.
The following is the standardized measure of discounted future net cash flows as of December
31, 2010 (in thousands):
2010 | ||||
Future cash inflows |
$ | 475,909 | ||
Future production taxes |
| |||
Future production costs |
(54,872 | ) | ||
Future net cash flows before discount |
421,037 | |||
10% discount to present value |
(189,795 | ) | ||
Standardized measure of discounted future net cash flows
related to proved oil and gas reserves(1) |
$ | 231,242 | ||
(1) | No provision for federal or state income taxes has been provided for in the calculation because taxable income is passed through to the unitholders of the Trust. |
Changes in Standardized Measure of Discounted Future Net Cash Flows:
The following schedule reconciles the changes from inception to December 31, 2010 in the
standardized measure of discounted future net cash flows relating to proved reserves (in
thousands):
2010 | ||||
Standardized measure of discounted future net cash flows at inception of Trust |
$ | 205,875 | ||
Net proceeds to the Trust |
(22,672 | ) | ||
Revisions of previous estimates |
(3,629 | ) | ||
Accretion of discount |
20,587 | |||
Net change in price and production cost |
37,682 | |||
Other |
(6,601 | ) | ||
Standardized measure of discounted future net cash flows at end of period |
$ | 231,242 | ||
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December 20, 2010
ECA Marcellus Trust I
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Suite 500
Austin, Texas 78701
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved
reserves, future production, and income attributable to certain royalty interests of ECA Marcellus
Trust I as of December 31, 2010. The subject properties are located in the state of Pennsylvania.
The reserves and income data were estimated based on the definitions and disclosure guidelines of
the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal
Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the
Federal Register (SEC regulations). The results of our third party study, completed on December 20,
2010, are presented herein. The properties reviewed by Ryder Scott represent 100 percent of the
total net proved gas reserves of ECA Marcellus Trust I.
The estimated reserves and future net income amounts presented in this report, as of December
31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this
report are based on the average prices during the 12-month period prior to the ending date of the
period covered in this report, determined as unweighted arithmetic averages of the prices in effect
on the first-day-of-the-month for each month within such period, unless prices were defined by
contractual arrangements as required by the SEC regulations. Actual future prices may vary
significantly from the prices required by SEC regulations; therefore, volumes of reserves actually
recovered and the amounts of income actually received may differ significantly from the estimated
quantities presented in this report. The results of this study are summarized below.
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SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain and Royalty Interests of
ECA Marcellus Trust I
As of December 31, 2010
Estimated Net Reserves and Income Data
Certain and Royalty Interests of
ECA Marcellus Trust I
As of December 31, 2010
Proved | ||||||||||||||||
Developed | ||||||||||||||||
Producing | Non-Producing | Undeveloped | Total Proved | |||||||||||||
Net Remaining Reserves |
||||||||||||||||
GasMMCF |
38,151 | 4,335 | 59,963 | 102,449 | ||||||||||||
Income Data |
||||||||||||||||
Future Gross Revenue |
$ | 177,224,127 | $ | 20,138,777 | $ | 278,545,731 | $ | 475,908,635 | ||||||||
Deductions |
20,433,824 | 2,321,988 | 32,116,137 | 54,871,949 | ||||||||||||
Future Net Income
(FNI) |
$ | 156,790,303 | $ | 17,816,789 | $ | 246,429,594 | $ | 421,036,686 | ||||||||
Discounted FNI @ 10% |
$ | 88,223,682 | $ | 10,533,827 | $ | 132,484,986 | $ | 231,242,495 |
All gas volumes are reported on an as sold basis expressed in millions of cubic feet (MMCF)
at the official temperature and pressure bases of the areas in which the gas reserves are located.
The estimates of the reserves, future production, and income attributable to properties in
this report were prepared using the economic software package PHDWin Petroleum Economic Evaluation
Software, a copyrighted program of TRC Consultants L.C. Ryder Scott has found this program to be
generally acceptable, but notes that certain summaries and calculations may vary due to rounding
and may not exactly match the sum of the properties being summarized. Furthermore, one line
economic summaries may vary slightly from the more detailed cash flow projections of the same
properties, also due to rounding. The rounding differences are not material.
The future gross revenue is normally after the deduction of production taxes but in the State
of Pennsylvania this is zero. For ECA Marcellus Trust I, the deductions only incorporate gas
transportation costs since the Trust will own only a royalty interest. The future net income is
before the deduction of state and federal income taxes and general administrative overhead, and has
not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash
on hand or undistributed income. Gas reserves account for the remaining 100 percent of total future
gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10
percent per annum compounded monthly. Future net income was discounted at four other discount
rates, which were also compounded monthly. These results are shown in summary form as follows.
Discounted Future Net Income | ||||
Discount Rate | As of December 31, 2010 | |||
Percent | Total Proved | |||
5 |
$ | 298,155,984 | ||
8 |
$ | 253,886,536 | ||
12 |
$ | 212,492,880 | ||
15 |
$ | 189,752,408 |
The results shown above are presented for your information and should not be construed as our
estimate of fair market value.
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Reserves Included in This Report
The proved reserves included herein conform to the definitions as set forth in the Securities
and Exchange Commissions Regulations Part 210.4-10(a). An abridged version of the SEC reserves
definitions from 210.4-10(a) entitled Petroleum Reserves Definitions is included as an attachment
to this report.
The various reserve status categories are defined in the attachment to this report entitled
Petroleum Reserves Definitions. The developed proved non-producing reserves included herein
consist of the behind-pipe category.
No attempt was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist. The gas volumes included herein do not attribute gas consumed in
operations as reserves.
Reserves are those estimated remaining quantities of petroleum which are anticipated to be
economically producible, as of a given date, from known accumulations under defined conditions. All
reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount
of reliable geologic and engineering data available at the time of the estimate and the
interpretation of these data. The relative degree of uncertainty may be conveyed by placing
reserves into one of two principal classifications, either proved or unproved. Unproved reserves
are less certain to be recovered than proved reserves and may be further sub-classified as probable
and possible reserves to denote progressively increasing uncertainty in their recoverability. At
ECA Marcellus Trust Is request, this report addresses only the proved reserves attributable to the
properties evaluated herein.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward. The reserves included herein were estimated using
deterministic methods.
Reserves estimates will generally be revised as additional geologic or engineering data become
available or as economic conditions change. Moreover, estimates of reserves may increase or
decrease as a result of future operations, effects of regulation by governmental agencies or
geopolitical or economic risks. As a result, the estimates of oil and gas reserves have an
intrinsic uncertainty. The reserves included in this report are therefore estimates only and should
not be construed as being exact quantities. They may or may not be actually recovered, and if
recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than
the estimated amounts.
ECA Marcellus Trust Is operations may be subject to various levels of governmental controls
and regulations. These controls and regulations may include matters relating to drilling,
production practices, environmental protection, pricing policies, various taxes and levies
including income tax and are subject to change from time to time. Such changes in governmental
regulations and policies may cause volumes of reserves actually recovered and amounts of income
actually received to differ from the estimated quantities.
The estimates of reserves presented herein were based upon a detailed study of the properties
in which ECA Marcellus Trust I as of December 31, 2010 owns an interest; however, we have not made
any field examination of the properties. No consideration was given in this report to potential
environmental liabilities that may exist nor were any costs included for potential liability to
restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination
results in the estimation of the quantities of recoverable oil and gas and the second determination
results in the estimation of the uncertainty associated with those estimated quantities in
accordance with the Securities and Exchange Commissions Regulations Part 210.4-10(a). The process
of estimating the quantities of recoverable oil and gas reserves relies on the use of certain
generally accepted analytical procedures. These analytical procedures fall into three broad
categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy.
These methods may be used singularly or in combination by the reserve evaluator in the process of
estimating the quantities of reserves. The reserve evaluator must select the method or combination
of methods which in their professional judgment is most appropriate given the nature and amount of
reliable geoscience and engineering data
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available at the time of the estimate, the established or anticipated performance
characteristics of the reservoir being evaluated and the stage of development or producing maturity
of the property.
In many cases, the analysis of the available geoscience and engineering data and the
subsequent interpretation of this data may indicate a range of possible outcomes in an estimate
irrespective of the method selected by the evaluator. When a range in the quantity of reserves is
identified, the evaluator must determine the uncertainty associated with the incremental quantities
of the reserves. If the reserve quantities are estimated using the deterministic incremental
approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by
the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve
quantities as proved, probable and/or possible that addresses the inherent uncertainty in the
estimated quantities reported. All quantities of reserves within the same reserve category have the
same level of uncertainty under the SEC definitions.
Estimates of reserves quantities and their associated reserve categories may be revised in the
future as additional geoscience or engineering data become available. Furthermore, estimates of
reserves quantities and their associated reserve categories may also be revised due to other
factors such as changes in economic conditions, results of future operations, effects of regulation
by governmental agencies or economic risks as previously noted herein.
The reserves for the properties included herein were estimated by performance methods or by
analogy. In general, reserves attributable to producing wells were estimated by performance methods
such as decline curve analysis which utilized extrapolations of historical production through
November, 2010. In certain cases, producing reserves were estimated by a combination of performance
and analogy if there was inadequate historical performance data to establish a definitive trend and
where the use of production performance data as the sole basis for the reserve estimates was
considered to be inappropriate. Reserves attributable to non-producing and undeveloped reserves
included herein were estimated by the analogy method which utilized all pertinent well and seismic
data available through November, 2010.
To estimate economically recoverable oil and gas reserves and related future net cash flows,
we consider many factors and assumptions including, but not limited to, the use of reservoir
parameters derived from geological and engineering data which cannot be measured directly, economic
criteria based on current costs and SEC pricing requirements, and forecasts of future production
rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated
to be economically producible based on existing economic conditions including the prices and costs
at which economic producibility from a reservoir is to be determined. While it may reasonably be
anticipated that the future prices received for the sale of production and the operating costs and
other costs relating to such production may also increase or decrease from existing levels, such
changes were, in accordance with rules adopted by the SEC, omitted from consideration in making
this evaluation.
Energy Corporation of America has informed us that they have furnished us all of the accounts,
records, geological and engineering data, and reports and other data required for this
investigation. In preparing our forecast of future production and income, we have relied upon data
furnished by Energy Corporation of America with respect to property interests owned, production and
well tests from examined wells, normal direct costs of operating the wells or leases, other costs
such as transportation and/or processing fees, ad valorem and production taxes, completion and
development costs, product prices based on the SEC regulations. Ryder Scott reviewed such factual
data for its reasonableness; however, we have not conducted an independent verification of the data
supplied by Energy Corporation of America. We consider the assumptions, data, methods and
procedures used in this report appropriate for the purpose hereof, and we have used all such
methods and procedures that we consider necessary and appropriate to prepare the estimates of
reserves and future net revenues herein.
Future Production Rates
Our forecasts of future production rates are based on historical performance from wells now on
production. Test data and other related information were used to estimate the anticipated initial
production rates for those wells or locations that are not currently producing. If no production
decline trend has been established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An
estimated rate of decline was then applied to depletion of the reserves. If a decline trend has
been established, this trend was used as the basis for estimating future production rates. For
reserves not yet on production, sales were estimated to commence at an anticipated date furnished
by Energy Corporation of America.
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The future production rates from wells now on production may be more or less than estimated
because of changes in market demand or allowables set by regulatory bodies. Wells or locations that
are not currently producing may start producing earlier or later than anticipated in our estimates.
Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices
during the 12-month period prior to the ending date of the period covered in this report,
determined as the unweighted arithmetic averages of the prices in effect on the
first-day-of-the-month for each month within such period, unless prices were defined by contractual
arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed
and determinable escalations, exclusive of inflation adjustments, were used until expiration of the
contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic
average as previously described.
Energy Corporation of America furnished us with the above mentioned average prices in effect
on December 31, 2010. These initial SEC hydrocarbon prices were determined using the 12-month
average first-day-of-the-month benchmark prices appropriate to the geographic area where the
hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as
described herein. The table below summarizes the benchmark prices and price reference used for
the geographic area(s) included in the report. In certain geographic areas, the price reference and
benchmark prices may be defined by contractual arrangements.
The product prices that were actually used to determine the future gross revenue for each
property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or
distance from market, referred to herein as differentials. The differentials used in the
preparation of this report were furnished to us by Energy Corporation of America.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for
differentials and referred to herein as the average realized prices. The average realized prices
shown in the table below were determined from the total future gross revenue before production
taxes and the total net reserves for the geographic area and presented in accordance with SEC
disclosure requirements for each of the geographic areas included in the report.
Average | Average | |||||||||||||||
Geographic | Price | Benchmark | Realized | |||||||||||||
Area | Product | Reference | Prices | Prices | ||||||||||||
United States |
Gas | Henry Hub | $4.38/MMBTU | $4.65/MCF |
The effects of derivative instruments designated as price hedges of oil and gas quantities are
not reflected in our individual property evaluations.
Costs
Operating costs for the leases and wells in this report are supplied by Energy Corporation of
America and include only those costs directly applicable to the leases or wells. The operating
costs include a portion of general and administrative costs allocated directly to the leases and
wells. For operated properties, the operating costs include an appropriate level of corporate
general administrative and overhead costs. No deduction was made for loan repayments, interest
expenses, or exploration and development prepayments that were not charged directly to the leases
or wells.
Development costs were furnished to us by Energy Corporation of America and are based on
authorizations for expenditure for the proposed work or actual costs for similar projects. Energy
Corporation of Americas estimates of zero abandonment costs after salvage value were used in this
report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage
value and makes no warranty for Energy Corporation of Americas estimate.
Because of the direct relationship between volumes of proved undeveloped reserves and
development plans, we include in the proved undeveloped category only reserves assigned to
undeveloped locations that we have been
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assured will definitely be drilled. Energy Corporation of America has assured us of their
intent and ability to proceed with the development activities included in this report, and that
they are not aware of any legal, regulatory, political or economic obstacles that would
significantly alter their plans.
Current costs used by Energy Corporation of America were held constant throughout the life of
the properties.
It should be noted that ECA Marcellus Trust I, which owns only a royalty interest, is only
subject to the gas transportation costs and all other costs are paid by the working interest owners
and for this analysis only impact the calculation of the economic limit of the properties.
Standards of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting firm that has been providing
petroleum consulting services throughout the world for over seventy years. Ryder Scott is
employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta,
Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the
size of our firm and the large number of clients for which we provide services, no single client or
job represents a material portion of our annual revenue. We do not serve as officers or directors
of any publicly-traded oil and gas company and are separate and independent from the operating and
investment decision-making process of our clients. This allows us to bring the highest level of
independence and objectivity to each engagement for our services.
Ryder Scott actively participates in industry related professional societies and organizes an
annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our
staff have authored or co-authored technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional skills by actively participating in
ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and
geoscientists have received professional accreditation in the form of a registered or certified
professional engineers license or a registered or certified professional geoscientists license,
or the equivalent thereof, from an appropriate governmental authority or a recognized
self-regulating professional organization.
We are independent petroleum engineers with respect to ECA Marcellus Trust I as of December
31, 2010. Neither we nor any of our employees have any interest in the subject properties, and
neither the employment to do this work nor the compensation is contingent on our estimates of
reserves for the properties which were reviewed.
The professional qualifications of the undersigned, the technical person primarily responsible
for evaluating the reserves information discussed in this report, are included as an attachment to
this letter.
Terms of Usage
The results of our third party study, presented in report form herein, were prepared in
accordance with the disclosure requirements set forth in the SEC regulations and intended for
public disclosure as an exhibit in filings made with the SEC by ECA Marcellus Trust I.
We have provided ECA Marcellus Trust I with a digital version of the original signed copy of
this report letter. In the event there are any differences between the digital version included in
filings made by ECA Marcellus Trust I and the original signed report letter, the original signed
report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination
by authorized parties in our offices. Please contact us if we can be of further service.
This report was prepared for the exclusive use and sole benefit of ECA Marcellus Trust I as of
December 31, 2010 and may not be put to other use without our prior written consent for such use.
The data and work papers used in the preparation of this report are available for examination by
authorized parties in our offices. Please contact us if we can be of further service.
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Very Truly Yours, RYDER SCOTT COMPANY,L..P. TBPE Firm Registration No. F-1580 |
||||
/s/ LARRY T. NELMS | ||||
Larry T. Nelms, P.E. | [SEAL] | |||
Managing Vice President | ||||
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Professional Qualifications of Primary Technical Person
The conclusions presented in this report are the result of technical analysis conducted by
teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Thomas Nelms is the
primary technical person responsible for the estimate of the reserves, future production and
income.
Nelms, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1983, is a Managing Senior
Vice President and also serves as a member of the Board of Directors, responsible for coordinating
and supervising staff and consulting engineers of the company in ongoing reservoir evaluation
studies worldwide. Before joining Ryder Scott, Nelms served in a number of engineering positions
with Dome Petroleum, Mizel Petro Resources and Exxon. For more information regarding Mr. Nelms
geographic and job specific experience, please refer to the Ryder Scott Company website at
www.ryderscott.com/Experience/Employees.
Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State
University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a
registered Professional Engineer in the State of Colorado. He is also a member of the Society of
Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman
of the Denver Section and also served for three years on the board of directors.
As part of his 2009 continuing education hours, Nelms attended an internally presented 16
hours of formalized training as well as the day long 2009 RSC Reserves Conference forum, and a
presentation at the Denver Section of SPEE by Dr. John Lee relating to the definitions and
disclosure guidelines contained in the United States Securities and Exchange Commission Title 17,
Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January
14, 2009 in the Federal Register. Nelms serves as the instructor of the PetroSkills course entitled
Oil & Gas Reserve Evaluation for a period of four years.
Based on his educational background, professional training and more than 25 years of practical
experience in the estimation and evaluation of petroleum reserves, Nelms has attained the
professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III
of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information
promulgated by the Society of Petroleum Engineers as of February 19, 2007.
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2,525,000
Common Units
Representing Beneficial Interests
ECA Marcellus Trust I
PRELIMINARY PROSPECTUS
, 2011
Citi
Oppenheimer & Co.
RBC Capital Markets
Table of Contents
PART II
INFORMATION REQUIRED IN THE REGISTRATION STATEMENT
Item 13. Other Expenses Of Issuance And Distribution.
Set forth below are the expenses (other than underwriting discounts and commissions) expected
to be incurred in connection with the issuance and distribution of the securities registered
hereby. With the exception of the Securities and Exchange Commission
registration fee and the FINRA fee, the amounts set forth below are estimates.
SEC Registration fee |
$ | 10,469 | ||
FINRA Fee |
$ | 9,518 | ||
Printing and engraving expenses |
$ | 50,000 | ||
Fees and expenses of legal counsel |
$ | 75,000 | ||
Accounting fees and expenses |
$ | 75,000 | ||
Miscellaneous |
$ | 5,013 | ||
Total |
$ | 225,000 | ||
Item 14. Indemnification Of Directors And Officers.
The trust agreement provides that the Trustee and its officers, agents and employees shall be
indemnified from the assets of the trust against and from any and all liabilities, expenses,
claims, damages or loss incurred by it individually or as Trustee in the administration of the
trust and the trust assets, including, without limitation, any liability, expenses, claims, damages
or loss arising out of or in connection with any liability under environmental laws, or in the
doing of any act done or performed or omission occurring on account of it being Trustee or acting
in such capacity, except such liability, expense, claims, damages or loss as to which it is liable
under the trust agreement. In this regard, the Trustee shall be liable only for fraud or gross
negligence or for acts or omissions in bad faith and shall not be liable for any act or omission of
any agent or employee unless the Trustee has acted in bad faith or with gross negligence in the
selection and retention of such agent or employee. The Trustee is entitled to indemnification from
the assets of the trust and shall have a lien on the assets of the trust to secure it for the
foregoing indemnification.
Item 15. Recent Sales Of Unregistered Securities.
On June 30, 2010, the registration statement on Form S-1/S-3 (Registration No. 333-165833-01)
filed by ECA and the Trust in connection with the initial public offering of the trust units was
declared effective by the Securities and Exchange Commission. On July 7, 2010, the Trust issued
17,605,000 trust units to ECA and/or the Private Investors in exchange for the conveyances made by
ECA of the interests described elsewhere in this Annual Report on Form 10-K. Immediately
thereafter, ECA completed an initial public offering of units of beneficial interest in the Trust,
selling 8,802,500 trust units. After completion of the closing transactions, but prior to exercise
of the underwriters overallotment option relating to the initial public offering, ECA retained an
ownership in 3,296,683 common units and 4,401,250 subordinated units, or 43.7% of the total trust
units issued and outstanding. The sale of the trust units to ECA and to the Private Investors was
exempt from registration by virtue of Section 4(2) of the Securities Act of 1933.
Item 16. Exhibits.
The following documents are filed as exhibits to this registration statement:
Exhibit | ||||
Number | Description | |||
1.1***
|
| Form of Underwriting Agreement | ||
3.1(1)
|
| Certificate of Trust of ECA Marcellus Trust I (Incorporated herein by reference to Exhibit 3.1 to Registration Statement on Form S-1 (Registration No. 333-165833)). |
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Exhibit | ||||
Number | Description | |||
3.2*
|
Amended and Restated Trust Agreement of ECA Marcellus Trust I, dated July 7, 2010, among Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Corporation Trust Company, as Delaware Trustee (Incorporated herein by reference to Exhibit 3.1 to the Trusts Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800)). | |||
5.1****
|
| Opinion of Richards, Layton & Finger, P.A. relating to the validity of the trust units | ||
8.1****
|
| Opinion of Vinson & Elkins L.L.P. relating to tax matters | ||
10.1*
|
| Perpetual Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.2*
|
| Perpetual Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.3*
|
| Private Investor Conveyance, dated July 7, 2010, among ECA Marcellus Trust I and certain private investors named therein. | ||
10.4*
|
| Assignment of Royalty Interest, dated effective April 1, 2010, from Eastern Marketing Corporation to The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.5*
|
| Term Overriding Royalty Interest Conveyance (PDP), dated effective April 1, 2010 from Energy Corporation of America to Eastern Marketing Corporation. | ||
10.6*
|
| Term Overriding Royalty Conveyance (PUD), dated effective April 1, 2010, from Energy Corporation of America to Eastern Marketing Corporation. | ||
10.7*
|
| Administrative Services Agreement, dated July 7, 2010, between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.8*
|
| Development Agreement, dated July 7, 2010, between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.9*
|
| Swap Agreement, dated July 7, 2010, between Energy Corporation of America and ECA Marcellus Trust I. | ||
10.10*
|
| Drilling Support Lien, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.11*
|
| Royalty Interest Lien, dated July 7, 2010, by and between Energy Corporation of America and The Bank of New York Mellon Trust Company, N.A., as Trustee. | ||
10.12*
|
| Registration Rights Agreement, dated July 7, 2010, by and among ECA Marcellus Trust I, Energy Corporation of America, and certain affiliates of Energy Corporation of America. | ||
23.1****
|
| Consent of Ernst & Young LLP | ||
23.2**
|
| Consent of Richards, Layton & Finger, P.A. (contained in Exhibit 5.1) | ||
23.3**
|
| Consent of Vinson & Elkins, L.L.P. (contained in Exhibit 8.1) | ||
23.4****
|
| Consent of Ryder Scott | ||
(1) | Filed as Exhibit 3.1 to Registration Statement on Form S-1 (Registration No. 333-165833) | |
* | Exhibit previously filed with the SEC and incorporated herein by reference to the exhibit of like designation filed with the Trusts Current Report on Form 8-K filed on July 13, 2010 (File No. 001-34800). | |
** | Filed herewith | |
*** | To be filed by amendment | |
**** | Previously filed with the Registration Statement on Form S-1 (Registration No. 333-172797) on March 14, 2011. | |
Item 17. Undertakings.
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a post-effective amendment
to this registration statement:
i. To include any propectus required by section 10(a)(3) of the Securities Act of
1933;
ii. To reflect in the prospectus any facts or events arising after the effective date of
the registration statement (or the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental change in the information set
forth in the registration statement. Notwithstanding the foregoing, any increase or
decrease in volume of securities offered (if the total dollar value of securities offered
would not exceed that which was registered) and any deviation from the low or high end of
the estimated maximum offering range may be reflected in the form of prospectus filed with
the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume
and price represent no more than 20% change in the maximum aggregate offering price set
forth in the Calculation of Registration Fee table in the effective registration
statement.
iii. To include any material information with respect to the plan of distribution not
previously disclosed in the registration statement or any material change to such
information in the registration statement;
(2) That for the purpose of determining any liability under the Securities Act of 1933, each such
post-effective amendment shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any of the securities being
registered which remain unsold at the termination of the offering.
(4) For the purpose of determining liability under the Securities Act to any purchaser,
each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an
offering, other than registration statements relying on Rule 430B or other than prospectuses
filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration
statement as of the date it is first used after effectiveness. Provided, however, that no
statement made in a registration statement or prospectus that is part of the registration
statement or made in a document incorporated or deemed incorporated by reference into the
registration statement or prospectus that is part of the registration statement will, as to a
purchaser with a time of contract of sale prior to such first use, supersede or modify any
statement that was made in the registration statement or prospectus that was part of the
registration statement or made in any such document immediately prior to such date of first use.
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(5) That for the purpose of determining liability of the registrant under the Securities Act to
any purchaser in the initial distribution of the securities, the undersigned registrant
undertakes that in a primary offering of securities of the undersigned registrant pursuant to
this registration statement, regardless of the underwriting method used to sell the securities
to the purchaser, if the securities are offered or sold to such purchaser by means of any of the
following communications, the undersigned registrant will be a seller to the purchaser and will
be considered to offer or sell such securities to such purchaser:
i. Any preliminary prospectus or prospectus of the undersigned registrant relating to
the offering required to be filed pursuant to Rule 424;
ii. Any free writing prospectus relating to the offering prepared by or on behalf of
the undersigned registrant or used or referred to by the undersigned registrant;
iii. The portion of any other free writing prospectus relating to the offering
containing material information about the undersigned registrant or its securities provided
by or on behalf of the undersigned registrant; and
iv. Any other communication that is an offer in the offering made by the undersigned
registrant to the purchaser.
(6) That for purposes of determining any liability under the Securities Act of 1933, the
information omitted from the form of prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of prospectus filed by the registrants pursuant
to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this
registration statement as of the time it was declared effective.
(7) That for the purpose of determining any liability under the Securities Act of 1933, each
post-effective amendment that contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering thereof.
The undersigned registrant hereby undertakes to deliver or cause to be delivered with the
prospectus, to each person to whom the prospectus is sent or given, the latest annual report to
security holders that is incorporated by reference in the prospectus and furnished pursuant to and
meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934;
and, where interim financial information required to be presented by Article 3 of
Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to each
person to whom the prospectus is sent or given, the latest quarterly report that is specifically
incorporated by reference in the prospectus to provide such interim financial information.
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be
permitted to directors, officers, and controlling persons of the registrants pursuant to the
foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy as expressed in
the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the registrants of expenses
incurred or paid by a director, officer or controlling person of a registrant in the successful
defense of any action, suit, or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the registrants will, unless in the
opinion of their respective counsel the matter has been settled by controlling precedent, submit to
a court of appropriate jurisdiction the question whether such indemnification by them is against
public policy as expressed in the Securities Act of 1933 and will be governed by the final
adjudication of such issue.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused
this registration statement to be signed on its behalf by the
undersigned thereunto duly authorized, in the City of Austin, State
of Texas, on March 25, 2011.
ECA MARCELLUS TRUST I |
||||
By: | The Bank of New York Mellon Trust Company, N.A. |
|||
By: | /s/ Mike J. Ulrich | |||
Name: | Mike J. Ulrich | |||
Title: | Vice President | |||
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