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ECT > SEC Filings for ECT > Form 10-Q on 8-Aug-2014All Recent SEC Filings

Show all filings for ECA MARCELLUS TRUST I

Form 10-Q for ECA MARCELLUS TRUST I


8-Aug-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.

References to the "Trust" in this document refer to ECA Marcellus Trust I. References to "ECA" in this document refer to Energy Corporation of America and its wholly-owned subsidiaries, and when discussing the conveyance documents, include the private investors. The following review of the Trust's financial condition and results of operations should be read in conjunction with the financial statements and notes thereto and the audited financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2013. The Trust's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the SEC's website at www.sec.gov and also at www.businesswire.com/cnn/ect.htm. Certain terms used herein are defined in Appendix A.

Note Regarding Forward-Looking Statements

This Form 10-Q contains "forward-looking statements" about ECA and the Trust and other matters discussed herein that are subject to risks and uncertainties. All statements other than statements of historical fact included in this document, including, without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" regarding the financial position, business strategy, production and reserve growth, development activities and costs and other plans and objectives for the future operations of ECA and all matters relating to the Trust are forward-looking statements. Actual outcomes and results may differ materially from those projected.

When used in this document, the words "believes," "expects," "anticipates," "intends" or similar expressions, are intended to identify such forward-looking statements. Further, all statements regarding future circumstances or events are 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 operation of natural gas wells;

future production costs;

the effects of existing and future laws and regulatory actions;

the effects of changes in commodity prices;

conditions in the capital markets;

          competition in the energy industry;



          the uncertainty of estimates of natural gas reserves and production;
and

other risks described under the caption "Risk Factors" in the Trust's Annual Report on Form 10-K for the year ended December 31, 2013.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of ECA and the Trust, including those referenced in Item 1A of Part II under the caption "Risk Factors." All subsequent written and oral forward-looking statements attributable to ECA or the Trust or persons acting on behalf of ECA or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

Overview

The Trust is a statutory trust created under the Delaware Statutory Trust Act. The Bank of New York Mellon Trust Company, N.A. serves as Trustee. The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Royalty Interests (described below), to distribute to the Trust unitholders cash that


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the Trust receives in respect of the Royalty Interests after payment of Trust expenses, and to perform certain administrative functions in respect of the Royalty Interests and the Trust units. The Trustee has no authority or responsibility for, and no involvement with, any aspect of the oil and gas operations on the properties to which the Royalty Interests relate. The Trust derives all or substantially all of its income and cash flows from the Royalty Interests, which in turn are subject to the hedge contracts described in Part I, Item 3. The Trust is treated as a partnership for federal and state income tax purposes.

ECA completed its drilling obligation to the Trust under the Development Agreement as of November 30, 2011, substantially in advance of the required completion date of March 31, 2014. Consequently, no additional wells will be drilled for the Trust. As of June 30, 2014 the Trust owns royalties in the 14 Producing Wells and the 40 development wells (52.06 Equivalent PUD Wells calculated in accordance with the Development Agreement) that are now completed and in production.

The Royalty Interests were conveyed from ECA's working interest in the Producing Wells and the PUD Wells limited to the Underlying Properties. 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 ECA's interest in the Producing Wells for a period of 20 years commencing on April 1, 2010 and 45% thereafter. The PUD Royalty Interest 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 ECA's interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. Approximately 50% of the originally estimated natural gas production attributable to the Royalty Interests had been hedged through March 31, 2014. See Item 3 regarding a more complete description of the hedge contracts.

ECA was obligated to drill all of the PUD Wells by March 31, 2014. As of November 30, 2011, ECA had fulfilled its drilling obligation to the Trust by drilling 40 PUD Wells (52.06 Equivalent PUD Wells), calculated as provided in the Development Agreement. The Trust was not responsible for any costs related to the drilling of development wells or any other development or operating costs. The Trust's cash receipts in respect of the Royalty Interests are determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and, prior to the expiration of the hedge arrangements on March 31, 2014, the Trust's cash available for distribution included any cash receipts from the hedge contracts. Cash available for distribution is also reduced by Trust administrative expenses and any amounts reserved for administrative expenses. Post-production costs generally consist of costs incurred to gather, compress, transport, process, treat, dehydrate and market the natural gas produced. Charges payable to ECA for such post-production costs on its Greene County Gathering System were limited to $0.52 per MMBtu gathered until ECA fulfilled its drilling obligation in 2011; 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 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) ECA's 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 the PUD Wells, 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 an example, assuming ECA owns a 100% working interest in a PUD Well, the applicable net revenue interest is calculated by multiplying ECA's percentage working interest in the 100% working interest well by the unburdened interest percentage (87.5%), and such well would have a minimum 87.5% net revenue interest. Accordingly, the Trust is entitled to a minimum of 43.75% of the production proceeds from the well provided in this example. To the extent ECA's working interest in a PUD Well is less than 100%, the Trust's share of proceeds would be proportionately reduced.

The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting Trust administrative expenses and costs and reserves therefor, on or about 60 days following the completion of each


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quarter. The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The Trust is scheduled to terminate in 2030.

The amount of Trust revenues and cash distributions to Trust unitholders will depend on, among other things:

natural gas prices received;

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

post-production costs and any applicable taxes; and

administrative expenses of the Trust including expenses incurred as a result of being a publicly traded entity, and any changes in amounts reserved for such expenses.

The amount of the quarterly distributions will fluctuate from quarter to quarter, depending on the proceeds received by the Trust, among other factors. There is no minimum required distribution.

Pursuant to IRC Section 1446, withholding tax on income effectively connected to a United States trade or business allocated to foreign partners should be made at the highest marginal rate. Under Section 1441, withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to foreign partners should be made at 30% of gross income unless the rate is reduced by treaty. This release is intended to be a qualified notice to nominees and brokers as provided for under Treasury Regulation
Section 1.1446-4(b) by ECA Marcellus Trust I, and while specific relief is not specified for Section 1441 income, this disclosure is intended to suffice.
Nominees and brokers should withhold 39.6% of the distribution made to foreign partners.

Results of Trust Operations

For the Three Months Ended June 30, 2014 compared to the Three Months Ended June 30, 2013

Distributable income for the three months ended June 30, 2014 decreased to $5.0 million from $8.4 million for the three months ended June 30, 2013. Compared to the quarter ended June 30, 2013, royalty income decreased $2.1 million, hedge proceeds decreased $1.3 million and general and administrative expenses increased $0.1 million.

Royalty income decreased from $7.4 million for the three months ended June 30, 2013 to $5.3 million for the three months ended June 30, 2014, a decrease of $2.1 million. This decrease was due primarily to a decrease in production, a decrease in the average sales price, and an increase in post production costs primarily due to timing, as described below.

The average sales price for gas production decreased from $4.25 per Mcf for the three months ended June 30, 2013 to $4.22 per Mcf for the three months ended June 30, 2014. This decrease in price was primarily the result of a $0.60 decrease in the average Basis compared to the prior period, largely offset by a $0.57 increase in the weighted average monthly closing NYMEX price for the current period to $4.66 per MMBtu compared to the quarter ended June 30, 2013 weighted average monthly closing NYMEX price of $4.09 per MMBtu.

Post production costs consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines and, as of July 2013, an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post production costs increased to $0.69 per Mcf for the quarter ended June 30, 2014 as compared to $0.60 per Mcf for the quarter ended June 30, 2013. Effective March 1, 2013, the filed tariff rate charged by Columbia Gas Transmission, LLC ("TCO") was reduced from $0.1996 per MMBtu to $0.1878 per MMBtu at a one hundred percent load factor. A one-time cash refund of approximately $0.3 million from TCO, representing retroactive application of the reduced rate covering the period from January 2012 through February 2013, was received in June


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2013. Post production costs were higher than the previous period primarily as a result of this refund during the prior period.

Production decreased 25% from 2,030 MMcf for the three months ended June 30, 2013 to 1,516 MMcf for the three months ended June 30, 2014. The decreased production was primarily a result of natural production declines that occur during the early life of a well.

Hedge proceeds decreased from $1.3 million for the three months ended June 30, 2013 to $0 for the three months ended June 30, 2014, a decrease of approximately $0.62 per Mcf as a result of the expiration of the $5.00 fixed price floor contract on March 31, 2014. The Trust had 1,380,000 MMBtu hedged during the three months ended June 30, 2013. As a result of the expiration of the hedge arrangements on March 31, 2014, no such hedge was in place during the three months ended June 30, 2014.

The floor hedging arrangements expired March 31, 2014. Distributions after the expiration of the hedging arrangements may be substantially more volatile, and could, depending on natural gas prices, be substantially lower or higher than those during the period that the hedging arrangements were in effect.

General and administrative expenses paid by the Trust were $0.4 million for the three months ended June 30, 2014 as compared to $0.3 million for the three months ended June 30, 2013. The increase in expenses was primarily related to an increase of $0.1 million in Trustee fees due to the timing of payment of invoices. The amount of the annual Trustee fee has not changed since the inception of the Trust. It may increase or decrease beginning in 2016.

For the Six Months Ended June 30, 2014 compared to the Six Months Ended June 30, 2013

Distributable income for the six months ended June 30, 2014 decreased to $10.8 million from $16.2 million for the six months ended June 30, 2013. Compared to the six months ended June 30, 2013, royalty income decreased $1.4 million, hedge proceeds decreased $3.3 million, general and administrative expenses increased $0.1 million and the Trustee established a cash reserve of $0.5 million.

Royalty income decreased from $13.3 million for the six months ended June 30, 2013 to $11.9 million for the six months ended June 30, 2014, a decrease of $1.4 million. This decrease was due to a decrease in production, partially offset by an increase in the average sales price and a decrease in post production costs.

The average sales price for gas production increased from $3.85 per Mcf for the six months ended June 30, 2013 to $4.54 per Mcf for the six months ended June 30, 2014. This increase in price was primarily the result of a $1.09 increase in the weighted average monthly closing NYMEX price for the current period to $4.79 per MMBtu compared to the six months ended June 30, 2013 weighted average monthly closing NYMEX price of $3.70 per MMBtu, partially offset by a $0.40 decrease in the average Basis compared to the prior period.

Post production costs consist of a post-production services fee together with a charge for electricity used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines and, as of July 2013, an additional gathering charge for system enhancements applicable to certain wells in an effort to increase production by reducing the high line pressure previously experienced by those wells. Overall, average post production costs decreased to $0.65 per Mcf for the six months ended June 30, 2014 as compared to $0.68 per Mcf for the six months ended June 30, 2013. Post production costs were lower than the previous period primarily as a result of a reduction in the firm transportation costs, partially offset by a cash refund discussed herein. Effective March 1, 2013, TCO's filed tariff rate was reduced from $0.1996 per MMBtu to $0.1878 per MMBtu at a one hundred percent load factor. A one-time cash refund of approximately $0.3 million from TCO representing retroactive application of the reduced rate covering the period from January 2012 through February 2013 was received in June 2013.

Production decreased 27% from 4,204 MMcf for the six months ended June 30, 2013 to 3,053 MMcf for the six months ended June 30, 2014. The decreased production was primarily a result of natural production declines that occur during the early life of a well.


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Hedge proceeds decreased from $3.6 million for the six months ended June 30, 2013 to $0.3 million for the six months ended June 30, 2014, a decrease of approximately $0.76 per Mcf primarily as a result of the expiration of the $5.00 fixed price floor contract on March 31, 2014. The Trust had 2,775,000 MMBtu hedged during the six months ended June 30, 2013 and 1,092,000 MMBtu hedged during the six months ended June 30, 2014.

The floor hedging arrangements expired March 31, 2014. Distributions after the expiration of the hedging arrangements may be substantially more volatile, and could, depending on natural gas prices, be substantially lower or higher than those during the period that the hedging arrangements were in effect.

General and administrative expenses paid by the Trust were $0.8 million for the six months ended June 30, 2014 as compared to $0.7 million for the six months ended June 30, 2013. The increase in expenses was primarily related to an increase in outside professional fees.

Prior to 2013, the Trustee established, and subsequently released, a net cash reserve for use in paying current and future liabilities of the Trust as they become due. During the six months ended June 30, 2014, the Trustee re-established a reserve of $500,000 for similar reasons, which decreased distributable income by $500,000.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than net cash flows from the Royalty Interests and proceeds from the hedge contracts, which expired as to production after March 31, 2014. Other than Trust administrative expenses, including, if applicable, expense reimbursements to ECA and any reserves established by the Trustee for future liabilities, the Trust's only use of cash is for distributions to Trust unitholders. 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 Royalty Interests and other sources (such as interest earned on any amounts reserved by the Trustee) that quarter, over the Trust's expenses for that quarter. 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 Trust's 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 Royalty Interests are based on the complex provisions of the various conveyances held by the Trust, copies of which are filed as exhibits to this report, 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 Trust's liquidity or the availability of capital resources.

Significant Accounting Policies

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, among other differences, certain cash reserves may be established for contingencies, which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the investment in overriding royalty interests calculated on a unit-of-production basis is charged directly to Trust Corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by ASC 932.

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 Interests are not burdened by field and lease operating expenses. Thus, the statement shows distributable income, defined as income of the Trust available for distribution


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to the Trust unitholders before application of those unitholders' additional expenses, if any, for depreciation, depletion, and amortization, interest and income taxes. The revenues are reflected net of existing royalties and overriding royalties and have been reduced by gathering/post-production expenses.

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 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 ASC 360. The Trust will determine if a write down 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. Determination as to whether and how much an asset is impaired involves estimates of highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on post-production costs and the outlook for national or regional market supply and demand conditions. If required, the Trust will provide a write down 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 write-down would not reduce Distributable Income, although it would reduce Trust Corpus. No impairment in the Underlying Properties has been recognized since inception of the Trust. 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 Trust's 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 Trust's investment in the Royalty Interests is not necessarily indicative of the fair value of such Royalty Interests.

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