e424b1
Filed
Pursuant to Rule 424(b)(1)
Registration Nos.
333-172797
and
333-165833
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 April 8, 2011
the last reported sales price of the trusts common units
on the New York Stock Exchange was $30.41 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 12 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
|
|
$
|
29.35
|
|
|
$
|
74,108,750
|
|
Underwriting discounts and commissions(1)
|
|
$
|
1.22
|
|
|
$
|
3,080,500
|
|
Proceeds to ECA (before expenses)
|
|
$
|
28.13
|
|
|
$
|
71,028,250
|
|
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 |
April 12, 2011
TABLE OF
CONTENTS
|
|
|
|
|
|
|
|
1
|
|
|
|
|
10
|
|
|
|
|
12
|
|
|
|
|
31
|
|
|
|
|
32
|
|
|
|
|
33
|
|
|
|
|
34
|
|
|
|
|
37
|
|
|
|
|
39
|
|
|
|
|
56
|
|
|
|
|
60
|
|
|
|
|
63
|
|
|
|
|
78
|
|
|
|
|
79
|
|
|
|
|
80
|
|
|
|
|
81
|
|
|
|
|
85
|
|
|
|
|
85
|
|
|
|
|
85
|
|
|
|
|
87
|
|
|
|
|
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 May 7, 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.
i
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
1
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 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
2
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 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
3
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
4
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 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.
|
5
|
|
|
|
|
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.
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
|
6
|
|
|
|
|
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 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 12. 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.
|
7
|
|
|
|
|
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 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. |
8
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.
9
THE
OFFERING
|
|
|
Common units offered to public |
|
2,525,000 units |
|
|
|
2,885,723 common units if the underwriters exercise their over
allotment option in full |
|
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. |
10
|
|
|
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. |
11
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.
|
12
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 Royalties Natural 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
13
revenues for the Underlying Properties could vary negatively and
in material amounts from estimates and those variations could be
material. Petroleum engineers are required to make subjective
estimates of underground accumulations of natural gas based on
factors and assumptions that include:
|
|
|
|
|
historical production from the area compared with production
rates from other producing areas;
|
|
|
|
natural gas prices, production levels, Btu content, production
expenses, transportation costs, severance and excise taxes and
capital expenditures; and
|
|
|
|
the assumed effect of governmental regulation.
|
Changes in these assumptions or actual production costs incurred
and results of actual development and production costs could
materially decrease reserve estimates.
In particular, reserve estimates for fields that do not have a
lengthy production history are less reliable than estimates for
fields with lengthy production histories. A lack of production
history may contribute to inaccuracy in estimates of proved
reserves, future production rates and the timing of development
expenditures. The Producing Wells have been operational for
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
14
expansion of pipeline transportation facilities will delay the
receipt of any proceeds that may be associated with natural gas
production from wells on the underlying PUD properties.
The
generation of proceeds for distribution by the Trust depends in
part on the ability of ECA and/or its customers to obtain
service on transportation facilities owned by third party
pipelines; any limitation in the availability of those
facilities and/or any increase in the cost of service on those
facilities could interfere with sales of natural gas production
from the Underlying Properties.
Natural gas that is gathered on 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
15
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 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.
16
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 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
|
17
|
|
|
|
|
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 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
Royalties Marketing 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.
18
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, 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
19
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.
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
|
20
|
|
|
|
|
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
Royalties Sale 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 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
21
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 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.
22
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 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.
23
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 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,
24
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 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
25
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
26
the anticipated cash flow and after-tax return to you, likely
causing a substantial reduction in the value of the trust units.
The Trust Agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects the Trust to taxation as a corporation or otherwise
subjects it to entity-level taxation for 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
27
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 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
28
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.
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.
29
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 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.
30
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.
31
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
April 8, 2011 was $30.41. As of April 8, 2011, there
were 18 holders of record of the common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
Unit Price
|
|
|
per Common
|
|
|
|
|
|
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
Unit
|
|
|
Record Date
|
|
|
Payment Date
|
|
|
June 30, 2011 (through April 8, 2011)
|
|
|
|
|
|
|
|
|
|
$
|
(1
|
)
|
|
|
(1
|
)
|
|
|
(1
|
)
|
March 31, 2011
|
|
$
|
31.98
|
|
|
$
|
25.50
|
|
|
$
|
(2
|
)
|
|
|
(2
|
)
|
|
|
(2
|
)
|
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
|
(3)
|
|
|
August 16, 2010
|
|
|
|
August 31, 2010
|
|
|
|
|
(1) |
|
The distributions attributable to the quarter ending
June 30, 2011 have not yet been declared or paid. |
|
(2) |
|
The distributions attributable to the quarter ending
March 31, 2011 have not yet been declared or paid. |
|
(3) |
|
These distributions were in excess of the target distributions
for such quarters and as a result ECA received incentive
distributions. |
32
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. |
33
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.
34
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.
35
Wells drilled horizontally in the Marcellus Shale formation with
a horizontal lateral distance (measured from the midpoint of the
curve to the end of the lateral) of less than 2,500 feet
will count as a fractional well in proportion to total lateral
length divided by 2,500 feet. In the event ECA commences
drilling of a PUD Well, but fails to drill beyond the mid-point
of the curve, such well will not count as a fractional well.
Wells with a horizontal lateral distance of greater than
2,500 feet (subject to a maximum of 3,500 feet) will
count as one well plus a fractional well equal to the length
drilled in excess of 2,500 (up to 3,500 feet) feet divided
by 2,500 feet. Among the 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.
36
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.
37
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.
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. |
38
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
39
December. These four 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.
40
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 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
41
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. |
|
(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
42
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 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
43
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.
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
44
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.
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.
|
45
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.
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
46
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 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
47
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
(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
48
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
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
49
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.
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
50
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 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
51
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 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.
52
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 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.
53
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.
|
54
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.
55
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;
|
56
|
|
|
|
|
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.
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
57
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
for any act or omission of its agents or employees unless the
Trustee acted with fraud, in bad
58
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.
59
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.
60
Each trust unitholder and his representatives may examine, for
any proper purpose, during reasonable business hours, the
records of the trust.
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.
61
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.
|
|
|
|
|
|
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.
|
62
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
|
63
|
|
|
|
|
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;
64
(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
(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
65
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.
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.
66
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.
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.
|
67
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) 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.
68
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.
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,
69
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, 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
70
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.
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;
|
71
|
|
|
|
|
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 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
72
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 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
73
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 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
74
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.
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.
75
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
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.
76
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:
(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.
77
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.
78
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.
79
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. |
80
UNDERWRITING
AND PLAN OF DISTRIBUTION
Subject to the terms and conditions in an underwriting agreement
dated April 12, 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.
|
|
|
1,893,750
|
|
Oppenheimer & Co. Inc.
|
|
|
315,625
|
|
RBC Capital Markets, LLC
|
|
|
315,625
|
|
|
|
|
|
|
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 $0.7320 per unit. If all of
the common units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The common units are offered by the underwriters
as stated in this prospectus, subject to receipt and acceptance
by them. The underwriters reserve the right to reject an order
for the purchase of the common units in whole or in part.
OPTION TO
PURCHASE ADDITIONAL COMMON UNITS
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
|
|
$
|
29.35
|
|
|
|
74,108,750
|
|
|
|
84,695,970.05
|
|
Underwriting discount and commissions
|
|
$
|
1.22
|
|
|
|
3,080,500
|
|
|
|
3,520,582,06
|
|
Proceeds to ECA (before expenses)
|
|
$
|
28.13
|
|
|
|
71,028,250
|
|
|
|
81,175,387.99
|
|
81
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
|
|
|
|
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
82
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.
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.
83
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.
84
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;
|
85
This report contains important information about the trust, its
financial condition and our results of operations.
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
86
GLOSSARY
OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST
In this prospectus the following terms have the meanings
specified below.
AMI The 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.
87
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 producible
from a given date forward, from known reservoirs, and under
existing economic conditions, operating methods, and government
regulations prior 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.
88
ECA
MARCELLUS TRUST I
To The Bank of New York Mellon Trust Company, N.A., as
Trustee of
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.
Pittsburgh, Pennsylvania
February 28, 2011
F-2
ECA
MARCELLUS TRUST I
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.
F-3
ECA
MARCELLUS TRUST I
FOR THE
PERIODS ENDED DECEMBER 31, 2010
|
|
|
|
|
|
|
|
|
|
|
From
|
|
|
Three Months
|
|
|
|
Inception
|
|
|
Ended
|
|
|
|
(Audited)
|
|
|
(Unaudited)
|
|
|
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.
F-4
ECA
MARCELLUS TRUST I
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
ECA
MARCELLUS TRUST I
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
F-6
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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 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
F-7
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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.
|
|
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 Activities Oil 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.
F-8
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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 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.
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
F-9
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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.
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 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.
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.
F-10
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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
|
|
|
|
|
|
|
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
Activities Oil 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. |
F-11
ECA
MARCELLUS TRUST I
NOTES TO
FINANCIAL STATEMENTS (Continued)
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
|
|
|
|
|
|
|
F-12
December 20, 2010
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.
A-1
SEC
PARAMETERS
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMCF
|
|
|
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
|
|
|
|
As of December 31, 2010
|
|
Discount Rate 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.
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.
A-2
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 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.
A-3
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
A-4
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.
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
|
|
|
|
|
Price
|
|
Benchmark
|
|
Realized
|
Geographic 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
A-5
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 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.
A-6
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.
Very Truly Yours,
RYDER SCOTT COMPANY,L..P.
TBPE Firm Registration
No. F-1580
Larry T. Nelms,
P.E. [SEAL]
Managing Vice President
A-7
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.
A-8
2,525,000 Common
Units
Representing Beneficial
Interests
ECA Marcellus
Trust I
PROSPECTUS
April 12, 2011
Oppenheimer &
Co.
RBC Capital Markets