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ECT > SEC Filings for ECT > Form 10-Q on 8-Nov-2013All Recent SEC Filings

Show all filings for ECA MARCELLUS TRUST I

Form 10-Q for ECA MARCELLUS TRUST I


8-Nov-2013

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, 2012. 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.

Results of Trust Operations

For the Three Months Ended September 30, 2013 compared to the Three Months Ended September 30, 2012

Distributable income for the three months ended September 30, 2013 decreased to $6.9 million from $9.1 million for the three months ended September 30, 2012. Compared to the quarter ended September 30, 2012, royalty income decreased $1.1 million, hedge proceeds decreased $1.0 million and general and administrative expenses increased $0.1 million.

Royalty income decreased from $6.3 million for the three months ended September 30, 2012 to $5.2 million for the three months ended September 30, 2013, a decrease of $1.1 million. This decrease was due to a decrease in production, partially offset by an increase in the average realized price and a decrease in post production costs.

The average price realized for the three months ended September 30, 2013 increased $0.67 per Mcf to $3.74 per Mcf as compared to $3.07 per Mcf for the three months ended September 30, 2012. This increase was the result of an increase in the average sales price for gas production and a decrease in post production costs. The average sales price, before the effects of hedges and post production costs, increased from $2.89 per Mcf for the three months ended September 30, 2012 to $3.51 per Mcf for the three months ended September 30, 2013. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.58 per MMBtu compared to the quarter ended September 30, 2012 weighted average monthly closing NYMEX price of $2.80 per MMBtu, partially offset by a $0.15 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, 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 $0.74 per Mcf for the quarter ended September 30, 2013 as compared to $0.77 per Mcf for the prior year's comparable period. These costs were lower primarily as a result of a decrease in the charges for electricity (used in lieu of gas) for compression and a reduction in the firm transportation rate charged by Columbia Gas Transmission, LLC ("TCO"). 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.

Production decreased 37% from 2,993 MMcf for the three months ended September 30, 2012 to 1,886 MMcf for the three months ended September 30, 2013. The decreased production was primarily a result of natural production declines that occur during the early life of a well.


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Hedged volumes for the quarters ended September 30, 2013 and 2012 totaled 1,278,000 MMBtu and 1,305,000 MMBtu, respectively, covered by a $5.00 per MMBtu floor price contract. Proceeds received by the Trust for the quarter ended September 30, 2013 were $1.8 million, as compared to $2.9 million for the quarter ended September 30, 2012. The decrease was primarily the result of an increase in the average NYMEX price as discussed previously.

The fixed price swap contracts terminated June 30, 2012. The floor hedging arrangements will terminate March 31, 2014. Distributions after the hedging arrangements terminate 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 are in effect.

For the quarter ended September 30, 2013, the distribution available to all Trust unitholders was $6,880,844, or $0.391 per unit. For the quarter ended September 30, 2012, because the Subordination Threshold for the quarter was $0.624, common unitholders were entitled to a distribution of $0.624 per unit, with the subordinated unitholders being entitled to a distribution of the remainder at $0.190 per unit. The table below shows the effect of the subordination threshold on the distribution for the quarter ended September 30, 2012:

                                                                          For the
                                                                       quarter ended
                                                                     September 30, 2012

Distributable income available to unitholders                       $          9,077,227

Common units outstanding                              13,203,750
Subordinated units outstanding                         4,401,250              17,605,000
Distributable income per unit before
subordination threshold                                             $              0.516

Subordination threshold per common unit                             $              0.624
Common units outstanding                                                      13,203,750
Distributable income payable to common
unitholders at subordination threshold level                        $          8,239,140

Distributable income available to subordinated
unitholders                                                         $            838,087
Subordinated units outstanding                                                 4,401,250
Distributable income per unit available to
subordinated unitholders                                            $              0.190

The Subordination Period terminated on December 31, 2012. Consequently, the fourth quarter of 2012 was the last quarter during which common unitholders had the protection of the subordination provisions. Upon termination of the Subordination Period, the 4,401,750 subordinated units converted to common units. As common units, such 4,401,750 units are now entitled to the same distributions as all other common units, and no common units will be entitled to any benefit formerly conferred upon them by the subordination provisions.

General and administrative expenses paid by the Trust were $0.2 million for the three months ended September 30, 2013 as compared to $0.1 million for the three months ended September 30, 2012. The increase in expenses was primarily related to the timing of payment of Trustee fees. The Trustee's fees for both the second and third quarters of 2013, totaling $0.1 million, were paid during the quarter ended September 30, 2013. The Trustee fee of $37,500 and the ECA administration fee of $15,000 applicable to the quarter ended September 30, 2012 were billed and paid by the Trust during the quarter ended December 31, 2012.


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For the Nine Months Ended September 30, 2013 compared to the Nine Months Ended September 30, 2012

Distributable income for the nine months ended September 30, 2013 decreased to $23.1 million from $26.6 million for the nine months ended September 30, 2012. Compared to the nine months ended September 30, 2012, royalty income increased $2.5 million, hedge proceeds decreased $5.7 million and general and administrative expenses decreased $0.2 million. During the nine months ended September 30, 2012 the Trustee released $0.5 million of cash reserves; no reserves were withheld or released during the nine months ended September 30, 2013.

Royalty income increased from $16.1 million for the nine months ended September 30, 2012 to $18.6 million for the nine months ended September 30, 2013, an increase of $2.5 million. This increase was due to an increase in the average realized price and a decrease in post production costs, partially offset by a decrease in production.

The average price realized for the nine months ended September 30, 2013 increased $0.68 per Mcf to $3.93 per Mcf as compared to $3.25 per Mcf for the nine months ended September 30, 2012. This increase was the result of an increase in the average sales price for gas production and a decrease in post production costs, partially offset by a decrease in the average hedged price. The average sales price, before the effects of hedges and post production costs, increased from $2.68 per Mcf for the nine months ended September 30, 2012 to $3.75 per Mcf for the nine months ended September 30, 2013. This increase in price was primarily the result of an increase in the weighted average monthly closing NYMEX price for the current period to $3.66 per MMBtu compared to the nine months ended September 30, 2012 weighted average monthly closing NYMEX price of $2.59 per MMBtu, partially offset by a $0.06 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, 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 $0.70 per Mcf for the quarter ended September 30, 2013 as compared to $0.75 per Mcf for the prior year's comparable period. Post production costs were lower than last year's comparable nine-month period primarily as a result of a reduction in the firm transportation rate charged by TCO. 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. Also, 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. These decreases were partially offset by an increase in the charges for electricity (used in lieu of gas) for compression.

Production decreased 27% from 8,354 MMcf for the nine months ended September 30, 2012 to 6,089 MMcf for the nine months ended September 30, 2013. The decreased production was primarily a result of natural production declines that occur during the early life of a well, partially offset by the result of nine wells that were turned online during the nine months ended September 30, 2012 being online for all of the nine months ended September 30, 2013.

Hedged volumes for the nine months ended September 30, 2013 totaled 4,053,000 MMBtu covered by a $5.00 per MMBtu floor price contract. For the nine months ended September 30, 2012, hedged volumes totaled 3,555,000 MMBtu consisting of 1,365,500 MMBtu covered by a fixed price swap at a price of $6.82 per MMBtu and 2,190,000 MMBtu covered by a $5.00 per MMBtu floor price contract resulting in an average hedge price of approximately $5.70 per MMBtu for the hedged volume. The average hedge price per MMBtu declined from $5.70 per MMBtu for the nine months ended September 30, 2012 to $5.00 per MMBtu for the nine months ended September 30, 2013 due to the expiration of the swap contracts. Although there was an increase in volumes covered by hedge contracts, proceeds received by the Trust for the nine months ended September 30, 2013 of $5.4 million, as compared to $11.1 million for the nine months ended September 30, 2012 decreased as a result of the decrease in hedge price and the increase in the average NYMEX price as discussed previously.

The fixed price swap contracts terminated June 30, 2012. The floor hedging arrangements terminate March 31, 2014. Distributions after the hedging arrangements terminate 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 are in effect.


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General and administrative expenses paid by the Trust were $0.9 million for the nine months ended September 30, 2013 as compared to $1.0 million for the nine months ended September 30, 2012. The decrease in expenses was primarily related to a decrease of $0.1 million in professional tax service fees paid.

Prior to 2012, the Trustee had 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 released the cash reserve during the nine months ended September 30, 2012, but may re-establish a reserve of any amount at any time. The release of the cash reserve increased distributable income for the nine months ended September 30, 2012.

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;

the ability of the Trust's hedge counterparties to meet their contractual obligations;

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, 2012.

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. This completion date was approximately 2.3 years in advance of the required completion date of March 31, 2014. Consequently, no additional wells will be drilled for the Trust, and the subordinated units automatically converted on a one-for-one basis into ECT Common Units on December 31, 2012. The last cash distribution supported by the ECT Subordinated Units was the cash distribution payable with respect to the proceeds for the fourth quarter of 2012, which was paid on February 28, 2013. Beginning with the cash distribution payable with respect to the first quarter of 2013, all ECT trust units share in all cash distributions on a pro rata basis. As of September 30, 2013 the Trust owns royalties in the 14 Producing Wells and the forty development wells (52.06 Equivalent PUD Wells calculated in accordance with the Development Agreement and as described in the Prospectus) 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 royalty interest in the Producing Wells 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 royalty interest in the PUD Wells 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 has 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 Royalties is determined after deducting post-production costs and any applicable taxes associated with the Royalty Interests, and the Trust's cash available for distribution includes any cash receipts from the hedge contracts and is reduced by Trust 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; 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.


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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 quarter. The first quarterly distribution was made on August 31, 2010 to record unitholders as of August 16, 2010. The Trust is expected 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;

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; and

the effects of the hedging arrangements, and the expiration of the hedging arrangements.

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. In order to provide support for cash distributions on the common units for a limited period of time, ECA agreed to subordinate 4,401,250 of the Trust units it originally acquired, which constituted 25% of the outstanding Trust units. The subordinated units were entitled to receive pro rata distributions from the Trust each quarter if and to the extent there was sufficient cash to provide a cash distribution on the common units which was at least equal to the applicable quarterly subordination threshold. However, if there was not sufficient cash to fund such a distribution on all Trust units, the distribution with respect to the subordinated units was 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 was 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 exceeded 150% of the subordination threshold for such quarter. ECA's right to receive the incentive distributions, and the benefits of the subordination provision to the holders of common units, terminated upon the expiration of the Subordination Period.

The subordinated units automatically converted into common units on a one-for-one basis and ECA's right to receive incentive distributions terminated on December 31, 2012. Because the Subordination Period terminated on December 31, 2012, the fourth quarter of 2012 was the last quarter that the common unitholders were eligible to receive a distribution in the amount of the Subordination Threshold. The table below sets forth the Target Distributions and the Subordination and Incentive Thresholds for each quarter through the fourth quarter of 2012.


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The effective date of the Trust was April 1, 2010, meaning the Trust has 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 July 7, 2010.

                  Subordination       Target        Incentive
                    Threshold      Distribution     Threshold

2010:
Second Quarter   $         0.181   $       0.227   $     0.272
Third Quarter              0.334           0.417         0.501
Fourth Quarter             0.478           0.597         0.716
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

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.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than net cash flows from the Royalty Interests and hedge proceeds, if any. 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 . . .

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