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ECT > SEC Filings for ECT > Form 10-K on 14-Mar-2014All Recent SEC Filings

Show all filings for ECA MARCELLUS TRUST I

Form 10-K for ECA MARCELLUS TRUST I


14-Mar-2014

Annual Report


Item 7. Trustee's Discussion and Analysis of Financial Condition and Results of Operation.

This document contains forward-looking statements, which describe current expectations or forecasts of future events. Please refer to "Forward-Looking Statements" which follows the Table of Contents of this Form 10-K for an explanation of these types of statements and their limitations.


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Results of Trust Operations

For the Twelve months ended December 31, 2013 compared to Twelve months ended December 31, 2012

Distributable income for the year ended December 31, 2013 decreased to $29.5 million from $35.6 million for the year ended December 31, 2012. Compared to the year ended December 31, 2012, royalty income increased $0.3 million, hedge proceeds decreased $6.2 million, and general and administrative expenses decreased $0.2 million. During the year ended December 31, 2012 the Trustee released $0.5 million of cash reserves; no reserves were withheld or released during the year ended December 31, 2013.

Royalty income increased from $23.2 million for the year ended December 31, 2012 to $23.5 million for the year ended December 31, 2013, an increase of $0.3 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 year ended December 31, 2013 increased $0.57 per Mcf to $3.90 per Mcf as compared to $3.33 for the year ended December 31, 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 $2.87 per Mcf for the year ended December 31, 2012 to $3.71 per Mcf for the year ended December 31, 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 $3.65 per MMBtu compared to the year ended December 31, 2012 weighted average monthly closing NYMEX price of $2.78 per MMBtu, partially offset by a $0.03 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 $0.71 per Mcf for the year ended December 31, 2013 as compared to $0.75 per Mcf for the year ended December 31, 2012. Post production costs were lower than the previous year primarily as a result of 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. 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 of $0.01 per Mcf in the charges for electricity (used in lieu of gas) for compression.

Production decreased 28% from 10,931 MMcf for the year ended December 31, 2012 to 7,835 MMcf for the year ended December 31, 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 year ended December 31, 2012 being online for all of the year ended December 31, 2013.

Hedged volumes for the year ended December 31, 2013 totaled 5,241,000 MMBtu covered by a $5.00 per MMBtu floor price contract. For the year ended December 31, 2012, hedged volumes totaled 4,917,000 MMBtu consisting of 1,365,000 MMBtu covered by a fixed price swap at a price of $6.82 per MMBtu and 3,552 ,000 MMBtu covered by a $5.00 per MMBtu floor price contract resulting in an average hedge price of approximately $5.51 per MMBtu for the hedged volume. The average hedge price per MMBtu declined from $5.51 per MMBtu for the year ended December 31, 2012 to $5.00 per


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MMBtu for the year ended December 31, 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 year ended December 31, 2013 of $7.1 million, as compared to the $13.2 million for the year ended December 31, 2012, decreased as a result of the decrease in the average 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 were in effect.

General and administrative expenses paid by the Trust were $1.1 million for the year ended December 31, 2013 as compared to $1.3 million for the year ended December 31, 2012. The decrease in expenses was primarily related to a decrease of $0.1 million in professional fees for tax services and a decrease of $0.1 million in legal costs during the year ended December 31, 2013.

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 year ended December 31, 2012, but may re-establish a reserve of any amount at any time. The release of the cash reserve increased distributable income for the year ended December 31, 2012.

For the Twelve months ended December 31, 2012 compared to the Twelve months ended December 31, 2011

Distributable income for the year ended December 31, 2012 decreased to $35.6 million from $41.9 million for the year ended December 31, 2011. Compared to the year ended December 31, 2011, royalty income decreased $11.7 million, hedge proceeds increased $4.6 million, and general and administrative expenses decreased $0.4 million. During the year ended December 31, 2012, the Trustee released a cash reserve of $0.5 million that it had established during the period ended December 31, 2010.

Royalty income decreased from $34.8 million for the year ended December 31, 2011 to $23.2 million for the year ended December 31, 2012, a decrease of $11.7 million. This decrease was due to a decrease in the average realized price and an increase in post production costs, partially offset by an increase in production.

The average price realized for the year ended December 31, 2012 declined $1.11 per Mcf to $3.33 per Mcf as compared to $4.44 per Mcf for the year ended December 31, 2011. This decrease was the result of a decrease in the average sales price for gas production, an increase in post production costs, and a decrease in the average hedged price. The average sales price, before the effects of hedges and post production costs, declined from $4.26 per Mcf for the year ended December 31, 2011 to $2.87 per Mcf for the year ended December 31, 2012. This decrease in price was primarily the result of a decline in the weighted average monthly closing NYMEX price for the year ended December 31, 2012 to $2.78 per MMBtu compared to the period ended December 31, 2011 weighted average monthly closing NYMEX price of $4.02 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, averaged $0.75 per Mcf for the year ended December 31, 2012 as compared to an average of $0.71 per Mcf for the year ended December 31, 2011. Post production costs were higher than the previous period as a result of firm transportation charges on the TCO interstate pipeline system beginning in August 2011, resulting in an average $0.08 per Mcf increase in costs from the year ended December 31, 2011. This was partially offset by an average $0.04 per Mcf decline in the charge for electricity usage from the year ended December 31, 2011 to the year ended December 31, 2012.


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Production increased 11% from 9,813 MMcf for the year ended December 31, 2011 to 10,931 MMcf for the year ended December 31, 2012. The increased production was primarily the result of an increase in the number of wells online and producing during the year ended December 31, 2012, partially offset by natural production declines. A total of fifty-four wells (14 PDP and 40 PUD Wells (52.06 Equivalent PUD Wells)) were online and producing as of December 31, 2012, while there were a total of forty-five wells (14 PDP and 31 PUD Wells (39.84 Equivalent PUD Wells)) online and producing as of December 31, 2011. The Trust experienced production curtailments during the year ended December 31, 2012 as a result of facility delays while waiting for government permits, which were approved during the second quarter of 2012. The additional gathering systems and/or transportation pipelines were constructed and became operational in late June 2012, allowing increased volumes.

Hedged volumes for the year ended December 31, 2012 totaled 4,917,000 MMBtu consisting of 1,365,000 MMBtu covered by a fixed price swap at a price of $6.82 per MMBtu and 3,552,000 MMBtu covered by a $5.00 per MMBtu floor price contract resulting in an average hedge price of approximately $5.51 per MMBtu for the hedged volume. For the year ended December 31, 2011, hedged volumes totaled 3,895,500 MMBtu consisting of 1,357,500 MMBtu covered by a fixed price swap at a price of $6.75 per MMBtu, 1,380,000 MMBtu covered by a fixed price swap at a price of $6.82 per MMBtu and 1,158,000 MMBtu covered by $5.00 per MMBtu floor price contracts resulting in an average hedge price of approximately $6.28 per MMBtu for the hedged volume. The average hedge price per MMBtu declined from $6.28 per MMBtu for the year ended December 31, 2011 to $5.51 per MMBtu for the year ended December 31, 2012 due to the expiration of the swap contracts and a larger floor position. Although there was a decrease in the average hedge price, proceeds received by the Trust for the year ended December 31, 2012 increased as a result of the decrease in the average NYMEX price as discussed previously and an increase in the volumes covered by the floor contracts.

General and administrative expenses paid by the Trust were $1.3 million for the year ended December 31, 2012 as compared to $1.6 million for the year ended December 31, 2011. The decrease in expenses was primarily related to a decrease of $0.6 million in state franchise taxes paid, partially offset by a $0.3 million increase in professional fees for tax services during the year ended December 31, 2012.

During the period ended December 31, 2010, the Trustee 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 year ended December 31, 2012, but may re-establish a reserve of any amount at any time. The release of the cash reserve increased distributable income for the year ended December 31, 2012.

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, to distribute to the Trust unitholders cash that 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 1. 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


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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 December 31, 2013 the Trust owns Royalty Interests in the 14 Producing Wells and the 40 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 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 has been hedged through March 31, 2014.

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 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 will terminate in March 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 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 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 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.


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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.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations other than the commodity hedge contracts disclosed in the section "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this Annual Report on Form 10-K.

Contractual Obligations

    A summary of the Trust's contractual obligations as of December 31, 2013 is
provided in the following table (in thousands):

                                                    Payments Due by Year
                          2014      2015      2016      2017      2018      Thereafter      Total
Administrative
services fee             $  60.0   $  60.0   $  60.0   $  60.0   $  60.0    $     600.0   $   900.0
Trustee administrative
fee                        150.0     150.0     150.0     150.0     150.0        1,500.0     2,250.0
Delaware trustee fee         2.5       2.5       2.5       2.5       2.5           25.0        37.5


                         $ 212.5   $ 212.5   $ 212.5   $ 212.5   $ 212.5    $   2,125.0   $ 3,187.5

Pursuant to the terms of the Administrative Services Agreement with ECA, the Trust is obligated to pay ECA an annual administrative services fee of $60,000 for accounting, bookkeeping and informational services relating to the Royalty Interests to be performed by ECA on behalf of the Trust throughout the term of the Trust. Pursuant to the Trust Agreement, the Trustee is to be paid an administrative fee of $150,000 per year until January 1, 2016, after which date the fee will be adjusted annually, up or down, by the amount of the change in the All Urban Consumers (CPI-U)-US City Average for the immediately preceding calendar year, not to exceed +/- 3% in any one year. The Trust is also obligated to pay the Delaware Trustee a fee of $2,500 per year, throughout the term of the Trust.

ECA and the Trustee each may terminate the provisions of the Administrative Services Agreement relating to the provision by ECA of administrative services at any time following delivery of notice no less than 90 days prior to the date of termination; provided, however, that ECA may not terminate the Administrative Services Agreement except in connection with ECA's transfer of some or all of the Subject Interests, as defined in the Conveyances, and then only with respect to the Services to be provided with respect to the Subject Interests being transferred, and only upon the delivery to the Trustee of an agreement of the transferee of such Subject Interests reasonably satisfactory to the Trustee in which such transferee assumes the responsibility to perform the Services relating to the Subject Interests being transferred.

New Accounting Pronouncements

None applicable.

Significant Accounting Policies

. . .

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