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ECT > SEC Filings for ECT > Form 10-Q on 9-Aug-2012All Recent SEC Filings

Show all filings for ECA MARCELLUS TRUST I

Form 10-Q for ECA MARCELLUS TRUST I


9-Aug-2012

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, as well as the Discussion and Analysis of Historical Results from the Producing Wells contained in the Prospectus. The Trust's Annual Report 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.

Results of Trust Operations

For the Three Months Ended June 30, 2012 compared to the Three Months Ended June 30, 2011

Distributable income for the three months ended June 30, 2012 decreased to $8.3 million from $11.1 million for the three months ended June 30, 2011. Compared to the quarter ended June 30, 2011, royalty income decreased $5.7 million, hedge proceeds increased $2.8 million and general and administrative expenses decreased $0.2 million.

Royalty income decreased from $9.9 million for the three months ended June 30, 2011 to $4.2 million for the three months ended June 30, 2012, a decrease of $5.7 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 three months ended June 30, 2012 declined $1.39 per Mcf to $3.27 per Mcf as compared to $4.66 per Mcf for the three months ended June 30, 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 $4.59


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per Mcf for the three months ended June 30, 2011 to $2.31 per Mcf for the three months ended June 30, 2012. This decrease in price was primarily the result of a decline in the weighted average monthly closing NYMEX price for the current quarter to $2.21 per Dth compared to the quarter ended June 30, 2011 weighted average monthly closing NYMEX price of $4.32 per Dth.

Post production costs, which consisted of a gathering fee together with a charge for electric 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 quarter ended June 30, 2012 as compared to an average of $0.64 per Mcf for the prior year's comparable quarter. Post production costs were higher than the previous year's quarter as a result of firm transportation charges on the Columbia Gas Transmission, L.L.C. interstate pipeline system beginning in August 2011, resulting in an average $0.15 per Mcf increase in costs from the comparable quarter in 2011. This was partially offset by an average $0.04 per Mcf decline in the charge for electric usage from the quarter ended June 30, 2011 to the current quarter.

Production increased 7% from 2,512 MMcf for the three months ended June 30, 2011 to 2,679 MMcf for the three months ended June 30, 2012. The increased production was primarily a result of an increase in the number of wells online and producing during the quarter ended June 30, 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 June 30, 2012, while there were a total of thirty-one wells (14 PDP and 17 PUD Wells (21.89 Equivalent PUD Wells)) online and producing as of June 30, 2011. Of the forty PUD Wells, six (8.22 Equivalent PUD Wells) of these wells were brought online during the quarter ended June 30, 2012. Three wells (4.02 Equivalent PUD Wells) were brought online in early May and three (4.20 Equivalent PUD Wells) were brought online in mid-June. Subsequently, these six wells (8.22 Equivalent PUD Wells) had an average daily production rate, net to the Trust, of 3,417 Mcf per day for June 2012. Because of gathering system constraints and three of the wells being in production for only a partial month, the average June production rate, as stated, does not represent the full potential of such wells. The average gross initial production for the first thirty days of production for the six wells brought online during the quarter ended June 30, 2012 (8.22 Equivalent PUD Wells) was 2,160 Mcf per well per day.

The Trust had experienced production curtailments during the current period as a result of facility delays while waiting for governmental permits, which have been approved as of June 30, 2012. As a result, production was curtailed due to high operating pressure. The current production was slightly above the design capacity of the Greene County Gathering System and above targeted production that was originally established at the formation of the Trust. The additional gathering systems and/or transportation pipelines were constructed and became operational in late June, allowing increased volumes.

Hedged volumes for the quarter ended June 30, 2012 totaled 1,198,500 Dth consisting of 682,500 Dth covered by a fixed price swap at a price of $6.82 per Dth and 516,000 Dth covered by a $5.00 per Dth floor price contract resulting in an average hedge price of approximately $6.04 per Dth for the hedged volume. For the quarter ended June 30, 2011 hedged volumes totaled 892,500 Dth consisting of 682,500 Dth covered by a fixed price swap at a price of $6.75 per Dth and 210,000 Dth covered by a $5.00 per Dth floor price contract resulting in an average hedge price of approximately $6.34 per Dth for the hedged volume. While this resulted in an increase in total hedge proceeds received by the Trust for the quarter ended June 30, 2012, the average hedge price per Dth declined from $6.34 per Dth for the quarter ended June 30, 2011 to $6.04 per Dth for the quarter ended June 30, 2012 primarily due to a larger floor position.

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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For the quarter ended June 30, 2012, the distribution available to all Trust units was $8,334,483, or $0.473 per unit. Because the subordination threshold for the quarter was $0.602, common unitholders are entitled to a distribution of $0.602 per unit with the subordinated unitholders entitled to a distribution of the remainder at $0.088 per unit. The table below shows the effect of the subordination threshold:

                                                                          For the
                                                                       quarter ended
                                                                       June 30, 2012
Distributable income available to unitholders                         $     8,334,483

Common units outstanding                                13,203,750
Subordinated units outstanding                           4,401,250         17,605,000
Distributable income per unit before subordination
threshold                                                             $         0.473

Subordination threshold per common unit                               $         0.602
Common units outstanding                                                   13,203,750
Distributable income payable to common unitholders
at subordination threshold level                                      $     7,948,657

Distributable income available to subordinated
unitholders                                                           $       385,826
Subordinated units outstanding                                              4,401,250
Distributable income per unit available to
subordinated unitholders                                              $         0.088

The Subordination Period will terminate on December 31, 2012.

General and administrative expenses paid by the Trust were $0.4 million for the three months ended June 30, 2012 as compared to $0.6 million for the prior year's comparable quarter. The decrease in expenses was primarily related to a decrease of $0.2 million in state franchise taxes paid. Cash reserves were unchanged during the quarters ended June 30, 2012 and 2011.

ECA completed its drilling obligation as of November 30, 2011. During the quarter ended June 30, 2012, six PUD Wells (8.22 Equivalent PUD Wells) were turned online and producing. As of June 30, 2012, all forty PUD Wells (52.06 Equivalent PUD Wells) were turned online and producing.

For the Six Months Ended June 30, 2012 compared to the Six Months Ended June 30, 2011

Distributable income for the six months ended June 30, 2012 decreased to $17.5 million from $20.3 million for the six months ended June 30, 2011. Compared to the six months ended June 30, 2011, royalty income decreased $8.0 million, hedge proceeds increased $4.5 million, general and administrative expenses decreased $0.3 million and the trustee released $0.5 million of cash reserves during the six months ended June 30, 2012.

Royalty income decreased from $17.8 million for the six months ended June 30, 2011 to $9.8 million for the six months ended June 30, 2012, a decrease of $8.0 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 six months ended June 30, 2012 declined $1.33 per Mcf to $3.35 per Mcf as compared to $4.68 per Mcf for the six months ended June 30, 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


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price. The average sales price, before the effects of hedges and post production costs, declined from $4.51 per Mcf for the six months ended June 30, 2011 to $2.56 per Mcf for the six months ended June 30, 2012. This decrease in price was primarily the result of a decline in the weighted average monthly closing NYMEX price for the current period to $2.47 per Dth compared to the six months ended June 30, 2011 weighted average monthly closing NYMEX price of $4.22 per Dth.

Post production costs, which consisted of a gathering fee together with a charge for electric used in lieu of gas for compression on the gathering system and firm transportation charges on interstate gas pipelines, averaged $0.74 per Mcf for the six months ended June 30, 2012 as compared to an average of $0.65 per Mcf for the prior year's comparable period. Post production costs were higher than the previous year's six-month period as a result of firm transportation charges on the Columbia Gas Transmission, L.L.C. interstate pipeline system beginning in August 2011, resulting in an average $0.15 per Mcf increase in costs from the comparable period in 2011. This was partially offset by an average $0.06 per Mcf decline in the charge for electric usage from the six months ended June 30, 2011 to the current period.

Production increased 16% from 4,609 MMcf for the six months ended June 30, 2011 to 5,361 MMcf for the six months ended June 30, 2012. The increased production was primarily a result of an increase in the number of wells online and producing during the six months ended June 30, 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 June 30, 2012, while there were a total of thirty-one wells (14 PDP and 17 PUD Wells (21.89 Equivalent PUD Wells)) online and producing as of June 30, 2011. Of the forty PUD Wells, nine (12.23 Equivalent PUD Wells) of these wells were brought online during the six months ended June 30, 2012. One well (1.40 Equivalent PUD Wells) was brought online in late January, two (2.61 Equivalent PUD Wells) in early March, three (4.02 Equivalent PUD Wells) in early May, and three (4.20 Equivalent PUD Wells) in mid-June. Subsequently, these nine wells (12.23 Equivalent PUD Wells) had an average daily production rate, net to the Trust, of 4,762 Mcf per day for June 2012. Because of gathering system constraints and three of the wells being in production for only a partial month, the average June production rate, as stated, does not represent the full potential of such wells. The average gross initial production for the first thirty days of production for the nine wells brought online in 2012, (12.23 Equivalent PUD Wells) was 1,914 Mcf per well per day.

The Trust had experienced production curtailments during the current period as a result of facility delays while waiting for governmental permits, which have been approved as of June 30, 2012. As a result, production was curtailed due to high operating pressure. The current production was slightly above the design capacity of the Greene County Gathering System and above targeted production that was originally established at the formation of the Trust. The additional gathering systems and/or transportation pipelines were constructed and became operational in late June, allowing increased volumes.

Hedged volumes for the six months ended June 30, 2012 totaled 2,250,000 Dth consisting of 1,365,000 Dth covered by a fixed price swap at a price of $6.82 per Dth and 885,000 Dth covered by a $5.00 per Dth floor price contract resulting in an average hedge price of approximately $6.10 per Dth for the hedged volume. For the six months ended June 30, 2011 hedged volumes totaled 1,726,500 Dth consisting of 1,357,500 Dth covered by a fixed price swap at a price of $6.75 per Dth and 369,000 Dth covered by a $5.00 per Dth floor price contract resulting in an average hedge price of approximately $6.38 per Dth for the hedged volume. While this resulted in an increase in total hedge proceeds received by the Trust for the six months ended June 30, 2012, the average hedge price per Dth declined from $6.38 per Dth for the six months ended June 30, 2011 to $6.10 per Dth for the six months ended June 30, 2012 primarily due to a larger floor position.

General and administrative expenses paid by the Trust were $0.9 million for the six months ended June 30, 2012 as compared to $1.2 million for the prior year's comparable period. The decrease in expenses was primarily related to a decrease of $0.4 million in state franchise taxes paid and a $0.1 million reduction in non-audit professional fees, partially offset by a $0.2 million increase in audit and tax service fees during the six months ended June 30, 2012. Cash reserves of $0.5 million were released during the six months ended June 30, 2012, which increased distributable income for the period, and were unchanged during the six months ended June 30, 2011.


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ECA completed its drilling obligation as of November 30, 2011. During the six months ended June 30, 2012, nine PUD Wells (12.23 Equivalent PUD Wells) were turned online and producing. As of June 30, 2012, all forty PUD Wells (52.06 Equivalent PUD Wells) were turned online and producing.

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 completion and operation of natural gas wells;

future production and development 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, including ECA, to meet their contractual obligations;

conditions in the capital markets;

          competition from others 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, 2011.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of ECA and the Trust, including 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 Royalties (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Royalties after payment of Trust expenses, and to perform certain administrative functions in respect of the Royalties 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 Royalties relate. The Trust derives all or substantially all of its income and cash flows from the Royalties, 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.


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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 Subordination Period will terminate on December 31, 2012. As of June 30, 2012 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 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 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 (the "PUD Royalty Interest" and together with the PDP Royalty Interest, "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 ECA's interest in the PUD Wells for a period of 20 years commencing on April 1, 2010 and 25% thereafter. As used herein, the term "Producing Wells" means the 14 Producing Wells as defined above, and does not include the PUD wells, even though some or all of the PUD wells may have been drilled and completed and may be producing. As of the formation of the Trust, approximately 50% of the estimated natural gas production attributable to the Trust's royalty interests had 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 during the Subordination Period.

ECA was obligated to drill all of the PUD Wells no later than March 31, 2014. As of November 30, 3011, 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 PDP and PUD Royalty Interests, and the Trust's cash available for distribution will include 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 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) 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 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 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.

Hedge proceeds realized for the quarter ended June 30, 2012 were approximately $4.6 million and approximately $8.2 million for the six months ended June 30, 2012. The swap hedging arrangements terminated June 30, 2012 and 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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The Trust expects to make 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 through (and including) the quarter ending March 31, 2030 (the "Termination Date").

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

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 ECA's costs associated with establishing the floor price contracts transferred to the Trust and interest on such amounts;

administrative expenses of the Trust and 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. However, in order to provide support for cash distributions on the common units for a limited period of time, ECA has agreed to subordinate 4,401,250 of the Trust units it initially acquired, which constitute 25% of the outstanding Trust units. While the subordinated units will be 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 thresholds set forth below, 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. ECA completed its drilling obligation during the fourth quarter of 2011 and accordingly, the Subordination Period will expire on December 31, 2012. During the Subordination Period, 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. ECA's right to receive the incentive distributions will terminate upon the expiration of the Subordination Period, which will end on December 31, 2012. Further, once the subordinated units convert to common units on December 31, 2012, holders of common units will no longer have any right to the benefits of the subordination provisions currently . . .

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