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NGT > SEC Filings for NGT > Form 10-Q on 9-Nov-2012All Recent SEC Filings

Show all filings for EASTERN AMERICAN NATURAL GAS TRUST | Request a Trial to NEW EDGAR Online Pro

Form 10-Q for EASTERN AMERICAN NATURAL GAS TRUST


9-Nov-2012

Quarterly Report


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

Cautionary Statement

This Form 10-Q includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-Q, including without limitation the statements under "Management's Discussion and Analysis of Financial Condition and Results of Operations" are forward-looking statements. Although ECA has advised the Trustee that it believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary Statements") are disclosed in this Form 10-Q and in the Trust's Annual Report on Form 10-K for the year ended December 31, 2011 and include the fact that none of the Trust, the Trustee or ECA is able to predict future gas prices, gas production levels, economic activity, legislation or regulation, or expenses of the Trust, including expenses that may be incurred with the sale of the Royalty NPI and the termination of the Trust. All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Statements. The Trust, the Trustee and ECA disclaim any obligation to update any forward-looking statements except as required by law.

General

Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for any final distribution to be made after the sale of the Royalty NPI as described herein. Any final distribution will be subject to the prior payment of all expenses and liabilities of the Trust, and to the establishment and funding of any reserves the Trustee deems appropriate for contingent liabilities. See "-Liquidation of the Trust," below.

The Trust entered into a Purchase and Sale Agreement dated October 24, 2012 (the "Softvest Purchase Agreement") with Softvest, LP, a Delaware limited partnership ("Softvest"), pursuant to which the Trust agreed to sell the Royalty NPI to Softvest as described therein for $6.5 million, subject to reduction based on decreases to the closing price of the NYMEX natural gas December 2012 contract compared to the price on October 18, 2012 and potential issues with title to the Royalty NPI. On November 5, 2012, ECA exercised its right of first refusal to purchase the Royalty NPI on the terms set forth in the Softvest Purchase Agreement. The sale price, after making the price adjustment required by the Softvest Purchase Agreement relating to decreases to the closing price of the NYMEX natural gas December 2012 contract, is expected to be $5,917,264. The Trust and ECA have agreed to close the sale of the Royalty NPI on January 10, 2013.

The expenses expected to be incurred in connection with the sale of the Royalty NPI include payment pursuant to the Sale Brokerage/Consulting Agreement dated August 16, 2012 (the "Brokerage Agreement") between the Trust and EnergyNet.com, Inc. ("EnergyNet"). The Brokerage Agreement provides that at the closing of a sale of the Royalty NPI or any portion thereof, during the term of the engagement or within 180 days following the end of the engagement, the Trust will pay EnergyNet a fee equal to 4.0% of the sales price if the sales price is $2 million or less, and an additional 2.0% of any amount of the sales price in excess of $2 million. The fee payable to EnergyNet pursuant to the Brokerage Agreement is expected to be $158,345.

Pursuant to the Softvest Purchase Agreement, Softvest had the right to a reduction of the purchase price in the event of defects in title to the Royalty NPI. However, in connection with its exercise of its right of first refusal, ECA noted that it will not require any review of the status of title to the Royalty NPI. Consequently, the Trust does not anticipate any reduction of the price for title issues.


In the Softvest Purchase Agreement, the Trust agreed to reimburse Softvest for up to $25,000 of Softvest's out-of-pocket expenses incurred on or after the date of the Softvest Purchase Agreement in connection with its review of title to the Royalty NPI if ECA exercised its right of first refusal after October 26, 2012. Because ECA exercised its right of first refusal after October 26, 2012, the Trust will be required to reimburse Softvest for up to $25,000 of such expenses. ECA has agreed to reimburse the Trust, for the benefit of the Trust unitholders, for any amounts the Trust may be required to pay to Softvest as reimbursement of Softvest's expenses.

In marketing the Royalty NPI, the Trustee solicited bids on the basis of the distribution for the third quarter of 2012 being for the account of the Trust, and the distribution for the fourth quarter of 2012 being for the account of the purchaser of the Royalty NPI. The Softvest Purchase Agreement, and the amount offered by Softvest, reflected that allocation of the distributions. Upon ECA's exercise of its right of first refusal, ECA became entitled to acquire the Royalty NPI on the terms of the Softvest Purchase Agreement, and consequently, ECA will be entitled, after the closing of the sale of the Royalty NPI, to any distribution for the fourth quarter of 2012. Therefore, although the purchase price for the Royalty NPI should reflect this allocation, unitholders will not receive any direct distribution relating to the fourth quarter of 2012 for revenues attributable to the Royalty NPI.

See "-Liquidation of the Trust," below.

The Trust does not conduct any operations or activities. The Trust's purpose is, in general, to hold the Net Profits Interests, to distribute the cash proceeds to Unitholders which the Trust receives in respect of the Net Profits Interests (net of Trust expenses), and to perform certain administrative functions in respect of the Net Profits Interests and the Depositary Units. The Trust derives substantially all of its income and cash flows from the Net Profits Interests. The Trust has no source of liquidity or capital resources other than the cash flows from the Net Profits Interests.

The Net Profits Interests were created pursuant to Conveyances from ECA to the Trust. In connection therewith, ECA assigned its rights under a gas purchase contract (the "Gas Purchase Contract"), which obligates Eastern Marketing, and now ECA as successor by merger, to purchase all of the natural gas produced from the Underlying Properties that is attributable to the Net Profits Interests. As a result of the merger ECA will purchase the gas on the same terms on which Eastern Marketing would have been obligated to purchase the gas pursuant to the Gas Purchase Contract.

The Conveyances and the Gas Purchase Contract entitle the Trust to receive an amount of cash for each calendar quarter equal to the Net Proceeds for such quarter. "Net Proceeds" for any calendar quarter generally means an amount of cash equal to (a) 90% of a volume of gas equal to (i) the volume of gas produced during such quarter attributable to the Underlying Properties less (ii) a volume of gas equal to "Chargeable Costs" for such quarter, multiplied by (b) the applicable price for such quarter under the Gas Purchase Contract. "Chargeable Costs" is that volume of gas which equates in value, determined by reference to the relevant sales price under the Gas Purchase Contract or the Conveyances, as applicable, to the sum of the "Operating Cost Charge", "Capital Costs" and "Taxes".

The "Operating Cost Charge" for 2012 was based on an annual rate of $599,556, and for 2011 was originally based on an annual rate of $658,604. The 2011 Operating Cost Charge was decreased during the quarter ended June 30, 2011 as a result of wells sold during the second quarter. As provided in the Conveyances, the Operating Cost Charge will fluctuate based on the lesser of (A) five percent (5%) or (B) a percentage, not less than zero percent (0%), equal to the percentage increase, if any, in the average weekly earnings of Crude Petroleum and Gas Production Workers for the last calendar year, as shown by the index of average weekly earnings of Crude Petroleum and Gas Production Workers, as published by the United States Department of Labor, Bureau of Labor Statistics, based on a December-to-December comparison.


During 2003, the United States Department of Labor, Bureau of Labor Statistics converted all of its industry-based statistics to a different reporting system that was developed in cooperation with the United States' North American Free Trade Agreement Partners, Canada and Mexico, in an effort to standardize and modernize reporting codes. As a result of this conversion, the Crude Petroleum and Gas Production Workers index is no longer available for use in the annual calculation of overhead adjustment called for in the various Council of Petroleum Accountants Societies, or COPAS, model forms after March 2003.

Research by COPAS covering a ten year period indicated that by blending the Oil and Gas Extraction Index with the Professional and Technical Services Index, the results approximate the data from the old Crude Petroleum and Natural Gas Workers Index. Accordingly, COPAS has calculated the percentage change in the simple average of the Oil and Extraction Index and the Professional and Technical Services Index, commencing in April 2004. This "Overhead Adjustment Index" has been provided as a guidance to the industry as a replacement index for use in calculating the overhead adjustment. The adjustment for the effective time period is 5%. Since the Conveyance Documents do not specifically provide for a replacement index if the Crude Petroleum and Gas Production Workers Index was no longer published, ECA believes, and advised the Trustee, that the "Overhead Adjustment Index" as calculated by COPAS is a reasonable index to utilize since the industry is generally adopting the same as a replacement. ECA, with the concurrence of the Trustee, will utilize this "Overhead Adjustment Index" to adjust the "Operating Cost Charge" so long as such index is published by COPAS.

The Operating Cost Charge is reduced for each well that is sold (free of the Net Profits Interests) or plugged and abandoned. Capital Costs are defined as ECA's working interest share of capital costs for operations on the Underlying Properties having a useful life of at least three years, and excluding any capital costs incurred in drilling the Development Wells. Taxes refer to ad valorem taxes, production and severance taxes, and other taxes imposed on ECA's or the Trust's interests in the Underlying Properties, or production therefrom.

Pursuant to the Gas Purchase Contract, ECA as successor by merger to Eastern Marketing, is obligated to purchase such gas production at a purchase price per Mcf equal to the Index Price. The Index Price for any quarter is determined solely by reference to the Variable Price component. The Variable Price for any quarter is equal to the Henry Hub Average Spot Price (as defined) per MMBtu plus $0.30 per MMBtu, multiplied by 110% to effect a fixed adjustment for Btu content. The Henry Hub Average Spot Price is defined as the price per MMBtu determined for any calendar quarter equal to the price obtained with respect to each of the three months in such quarter, in the manner specified below, and then taking the average of the prices determined for each of such three months. The price determined for any month of such quarter is equal to the average of
(i) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts (as defined), as reported in The Wall Street Journal, for such contracts which expired in each of the five months prior to such month; (ii) the final settlement price per MMBtu for Henry Hub Gas Futures Contracts, as reported in The Wall Street Journal, for such contracts which expire during such month; and
(iii) the closing settlement price per MMBtu of Henry Hub Gas Futures Contracts determined as of the contract settlement date for such month, as reported in The Wall Street Journal, for such contracts which expire in each of the six months following such month. A Henry Hub Gas Futures Contract is defined as a gas futures contract for gas to be delivered to the Henry Hub that is traded on the New York Mercantile Exchange.

Accordingly, the Index Price payable to the Trust for production may be higher or lower based on the fluctuations in natural gas futures prices during the relevant calculation period. The price payable to the Trust will have a direct impact, positively or negatively, on the quarterly Distributions Payable by the Trust to its Unitholders.


ECA had a disagreement with the Trust in 1997 over ECA's obligation to drill certain Development Wells that were closely offset by third parties. The Trust agreed that in lieu of drilling these closely offset Development Wells, ECA could provide the Trust, on an annual basis commencing on April 1, 1997, and over the remaining life of the Trust, a volume of gas which is equal to the projected volumes of the wells as if they had been drilled. These volumes have been estimated by Ryder Scott Company, independent petroleum engineers. During the quarter ended September 30, 2012, payment for an additional volume of 2,389 Mcf was delivered to the Trust, as compared to a payment for 2,582 Mcf for the quarter ended September 30, 2011. These additional payments fulfill ECA's agreement to provide payment for the quarter for volumes for Development Wells that had been closely offset by third parties.

ECA has fulfilled its obligation with respect to the drilling of the Development Wells. Since the inception of the Trust, ECA has drilled a total of 59 Development Wells, which are online and producing. (See the Trust's Annual Report on Form 10-K for the year ended December 31, 2011, for a more complete description of the Development Wells.)

During the first half of 2011, ECA entered into two separate Purchase and Sale Agreements to sell certain assets to unrelated third parties in which the Trust owned a Net Profits Interest. As of January 1, 2010 ECA can transfer the Underlying Properties and require the Trust to release the NPI burdening that property, without the consent of the Trustee or Unitholders, subject to payment to the Trust of the fair value of the interest released. ECA finalized the sale of the assets, as described in the Purchase and Sale Agreements, in the quarter ended June 30, 2011. ECA received sale proceeds for the wells in the amount of $588,911. The Trust's share of the sales proceeds was $181,928 and was included in the Distributable Income of the Trust during the quarter ended June 30, 2011.

Over the remaining life of the Trust, wells may be disposed of from time to time in accordance with the documents governing the Trust.

The administrative costs the Trust incurs in the future will fluctuate depending primarily on the expenses the Trust incurs for professional services, particularly legal, accounting and engineering services, including expenses the Trust incurs in connection with its sale of the Royalty NPI, which are expected to be significantly greater than the routine historical administrative expenses the Trust has typically incurred. The expenses expected to be incurred in connection with the sale of the Royalty NPI include payment pursuant to the Sale Brokerage/Consulting Agreement dated August 16, 2012 (the "Brokerage Agreement") between the Trust and EnergyNet.com, Inc. ("EnergyNet"). As previously disclosed, pursuant to the Brokerage Agreement, the Trust engaged EnergyNet to perform sales brokerage and consulting services in connection with the Trust's anticipated sale of the Royalty NPI. The Brokerage Agreement provides that at the closing of a sale of the Royalty NPI or any portion thereof, during the term of the engagement or within 180 days following the end of the engagement, the Trust will pay EnergyNet a fee equal to 4.0% of the sales price if the sales price is $2 million or less, and an additional 2.0% of any amount of the sales price in excess of $2 million. The fee payable to EnergyNet pursuant to the Brokerage Agreement is expected to be $158,345.

Liquidation of the Trust

The Trust will be liquidated and the Royalty NPI will be sold prior to the Liquidation Date, which is expected to occur in 2013. Unitholders of record as of the record date for the final quarter of the Trust's existence will be entitled to receive a terminating distribution with respect to each Depositary Unit equal to a pro rata portion of the net proceeds from the sale of the Royalty NPI (to the extent not previously distributed) and a pro rata portion of the proceeds from the matured Treasury Obligations (to the extent not previously withdrawn). The Term NPI will expire by its terms no later than May 15, 2013, and the Trust will not realize any further value from the Term NPI after such date.


As described above, on August 16, 2012 the Trust entered into the Brokerage Agreement, pursuant to which the Trust engaged EnergyNet to perform sales brokerage and consulting services in connection with the Trust's anticipated sale of the Royalty NPI. EnergyNet subsequently informed the Trustee that its marketing activities resulted in 190 companies reviewing materials relating to the Royalty NPI, with approximately ten of the companies conducting more extensive reviews. EnergyNet then solicited bids for the Royalty NPI. The highest bid submitted was the bid submitted by Softvest, which subsequently entered into the Softvest Purchase Agreement with the Trust described above.

Pursuant to the Trust Agreement, ECA, which held a right of first refusal to purchase the Royalty NPI from the Trust, had the right to require the Trust to engage an appraiser to appraise the Royalty NPI if the Trust had not sold the Royalty NPI by September 30, 2012. ECA also had the right to purchase the Royalty NPI at the appraised value. At the request of the Trustee, on September 25, 2012, ECA granted a waiver in order to allow the Trust additional time in which to market the Royalty NPI. ECA further agreed to waive the 20-business day notice of a proposed sale to which it was entitled under the Trust Agreement in order to allow the Trust additional time in which to market the Royalty NPI, and agreed to accept a shorter notice period.

On October 5, 2012 ECA informed the Trustee that ECA had estimated the present value of the Asset Retirement Obligation, as defined under Generally Accepted Accounting Principles, attributable to the Trust's Royalty NPI associated with potential plugging and abandonment liabilities for wells in which the Trust holds its Royalty NPI at between $2.7 million and $5.0 million. ECA further advised the Trustee that its estimate range is net of estimated salvage value. ECA noted that the Asset Retirement Obligation attributable to the Royalty NPI could be considered a Capital Cost under the terms of the Royalty NPI Conveyance, and that if such a determination were made, the costs would be chargeable against future distributions to a future purchaser of the Royalty NPI or to the Trust. During the approximately 20 years that the Trust has been in existence, ECA has not charged any amounts for accrued or estimated future plugging and abandonment liabilities against amounts payable to the Trust pursuant to either the Royalty NPI or the Term NPI. Although no final determination regarding the matter has been made, the Trustee was obligated to advise EnergyNet and thus potential purchasers of the NPI of ECA's communication regarding the potential charges, and did so promptly.

As described above, on October 24, 2012 the Trust and Softvest entered into the Softvest Purchase Agreement. Subsequently, on November 5, 2012, ECA delivered a notice to the Trustee in which ECA elected to exercise its right of first refusal to purchase the Royalty NPI on the terms sets forth in the Purchase Agreement. The material terms of the Softvest Purchase Agreement and of ECA's exercise of its right of first refusal are described above. See "-General," above.

Pursuant to the Trust Agreement, all proceeds of any sale received by the Trustee after December 31, 2012, and all other receipts of the Trust received after December 31, 2012, will be retained by the Trustee until the final distribution. Consequently, Unitholders will not receive any distribution of any amount from the Trust relating to amounts received by the Trust after December 31, 2012 except for any final distribution. Subject to the payment of all expenses and liabilities of the Trust, and subject to the creation and funding of cash reserves in such amounts as the Trustee in its discretion deems appropriate for contingent liabilities, all amounts then held by the Trust, including the net proceeds of the sale of the Royalty NPI, will be distributed to Unitholders of record as of the record date for the final quarter of the Trust's existence.

In marketing the Royalty NPI, the Trustee solicited bids on the basis of the distribution for the third quarter of 2012 being for the account of the Trust, and the distribution for the fourth quarter of 2012 being for the account of the purchaser of the Royalty NPI. The Softvest Purchase Agreement, and the amount offered by Softvest, reflected that allocation of the distributions. Upon ECA's exercise of its right of first refusal, ECA became entitled to acquire the Royalty NPI on the terms of the Softvest Purchase Agreement, and consequently, ECA will be entitled, after the closing of the sale of the


Royalty NPI, to any distribution for the fourth quarter of 2012. Therefore, although the purchase price for the Royalty NPI should reflect this allocation, unitholders will not receive any direct distribution relating to the fourth quarter of 2012 for revenues associated with the Royalty NPI.

Critical Accounting Policies

The following is a summary of the critical accounting policies followed by the Trust.

Basis of Accounting:

The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America due to the following: (i) certain cash reserves may be established for contingencies which were not accrued in the financial statements; (ii) amortization of the Net Profits Interests in Gas Properties is charged directly to Trust Corpus; (iii) the sale of the Net Profits Interests is reflected in the Statements of Distributable Income as cash proceeds to the Trust; and (iv) the presentation of a Statement of Cash Flows is not required.

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with accounting principles generally accepted in the United States of America. Because the Trust's financial statements are prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America, as described above, most accounting pronouncements are not applicable to the Trust's financial statements.

Net Profits Interests in Gas Properties:

The Net Profits 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 writedown is necessary to its investment in the Net Profits Interests in gas properties to the extent that total capitalized costs, less accumulated amortization, exceed undiscounted future net revenues attributable to proved gas reserves of the Underlying Properties. The Trust will then provide a writedown to the extent that the net capitalized costs exceed the fair value of the investment in net profits interests attributable to proved gas reserves of the Underlying Properties. Any such writedown would not reduce Distributable Income, although it would reduce Trust Corpus. See Note 5 to the Financial Statements.

Significant dispositions or abandonment of the Underlying Properties are charged to Net Profits Interests and the Trust Corpus.

Amortization of the Net Profits Interests in gas properties is calculated on a units-of-production basis, whereby the Trust's cost basis in the properties is divided by total Trust 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 Net Profits Interest impairment test and the determination of amortization rates are dependent on estimates of proved gas reserves attributable to the Trust. Numerous uncertainties are inherent in estimating reserve volumes and values, including economic and operating conditions, and such estimates are subject to change as additional information becomes available.

Recent Accounting Pronouncements

Recent pronouncements issued by the FASB or other authoritative accounting standards groups with future effective dates are either not applicable or are not expected to be significant to the Trust's financial statements.


Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than the distributions received from the Net Profits Interests.

In accordance with the provisions of the Conveyances, generally all revenues received by the Trust, net of Trust administrative and operating expenses and the amount of established reserves, are distributed currently to the Unitholders.

The Trust did not have any contractual obligations as of September 30, 2012 other than its contractual obligations to EnergyNet under the Brokerage Agreement described above. As described above, the fee payable to EnergyNet is expected to be $158,345, which will become payable upon the closing of the sale of the Royalty NPI, which is scheduled to occur on January 10, 2013. At September 30, 2012, the Trust had Trust General and Administrative Expenses Payable of $234,291 and Distributions Payable of $784,885.

Comparison of Results of Operations for Three Months Ended September 30, 2012 and Three Months Ended September 30, 2011

The Trust's Distributable Income was $784,885 for the three months ended September 30, 2012 as compared to $1,431,801 for the three months ended September 30, 2011. This decrease was due to a decrease in Royalty Income of $532,315 ($1,388,195 for the three months ended September 30, 2012 as compared to $1,920,510 for the three months ended September 30, 2011). This decrease in Royalty Income was related to a decrease in the price payable to the Trust under the Gas Purchase Contract as discussed below ($3.427 per Mcf for the three months ended September 30, 2012 as compared to $5.084 per Mcf for the three months ended September 30, 2011). Offsetting this decrease was an increase in production of gas attributable to the Net Profits Interests for the three months ended September 30, 2012 (405 MMcf) as compared to the three months ended September 30, 2011 of (378 MMcf). The increase in production is primarily attributable to increased production from several wells in West Virginia which are located in an area experiencing increased drilling and completion activities, partially offset by natural production declines. Taxes on Production and Property were $104,132 for the three months ended September 30, 2012 as compared to $135,234 for the three months ended September 30, 2011. The decrease . . .

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