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NGT > SEC Filings for NGT > Form 10-Q on 8-Aug-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


8-Aug-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. 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 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. As discussed below, the 2011 Operating Cost Charge was decreased during the quarter ended June 30, 2011 as a result of wells sold during the second


quarter. These sold wells reduced the Operating Cost Charge for the quarter ended June 30, 2012. 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. As a result of selling wells, the Operating Cost Charge was reduced by $21,629 in the quarter ended June 30, 2011 and this reduction is applicable for all quarters thereafter. 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 June 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 June 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.

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). Under the Trust Agreement, ECA has a right of first refusal to purchase the Royalty NPI at fair market value, or, if applicable, the offered third-party price, prior to the Liquidation Date. 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.


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 all remaining Royalty NPI interests have been sold. 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 to be made after the sale of the Royalty NPI described herein. 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 will be distributed to Unitholders of record as of the record date for the final quarter of the Trust's existence.

Subject to ECA's rights of first refusal and other provisions of the Trust Agreement described herein, the Trustee is required to use its best efforts to sell the Royalty NPI for cash, prior to May 15, 2013.

If the Trustee has not sold the Royalty NPI on or prior to September 30, 2012, the Trustee is required to engage an independent appraiser (at the expense of the Trust) to appraise the fair value of the NPI as of September 30, 2012, and to deliver a copy of such appraisal to ECA by November 15, 2012. ECA will then be entitled but not obligated to purchase the Royalty NPI for cash at the appraised value (less the aggregate amount of distributions made to the Trust from the Royalty NPI since September 30, 2012) by delivery of a notice to the Trustee given within ten business days from ECA's receipt of the appraiser's report. If ECA elects not to purchase the Royalty NPI, the Trustee is required to take all reasonable actions within its discretion necessary to arrange for an unreserved auction or sealed bid sale (collectively, the "March 1, 2013 Sale") of the Royalty NPI to be held on March 1, 2013, and to sell the Royalty NPI to the highest cash bidder at the auction or sale.

The Trustee will mail notice of any March 1, 2013 Sale, if one occurs, to each Trust Unitholder at his or her address as it appears in the records of the Trustee at least 60 days prior to any such sale. However, no approval of the Trust Unitholders will be required or sought prior to any such sale of the Royalty NPI or any portion thereof as described herein. If the Trustee sells the Royalty NPI prior to March 1, 2013, no notice of the sale will be mailed to Unitholders.

In addition to ECA's purchase right at an appraised fair value as described above, ECA has the right under the Trust Agreement to purchase any or all of the Royalty NPI from the Trust on the same price and terms as those offered by any person in any proposed sale. Further, in the event of a proposed disposition by auction or sealed bid, ECA has an additional right to purchase the Royalty NPI to be sold as described below.

Except for proposed dispositions by auction or sealed bid, the Trustee is required to give written notice to ECA at least 20 business days prior to the date of any proposed disposition setting forth in reasonable detail a description of the Royalty NPI to be sold, and the proposed price and terms of such disposition. ECA may exercise its right to purchase the Royalty NPI to be sold by giving written notice to the Trustee no later than ten business days from the date of receipt of such notice.

In the event the Trustee gives notice of a proposed disposition of all or a portion of the Royalty NPI by auction or sealed bid at the March 1, 2013 Sale, the Trustee shall prior to such auction or bid, unless the right of first refusal is waived by ECA, engage (at the expense of the Trust) an independent appraiser to appraise the fair value (as of the date of such notice) of the portion of the Royalty NPI proposed to be sold. Upon receipt of the appraisal, ECA may exercise its option to acquire the portion of the Royalty NPI proposed to be sold for cash in the amount of the appraised value (less the aggregate amount of distributions made to the Trust from that portion of the Royalty NPI since the date of the appraised value) by delivery of a written election notice to the Trustee within ten business days from the date of receipt by ECA of the independent appraiser's report.


In the event the Trustee gives notice of a proposed disposition of all or a portion of the Royalty NPI by auction or sealed bid, and ECA does not exercise its option to acquire the portion of the Royalty NPI proposed to be sold, ECA could, but would not be required to, bid for the Royalty NPI to be sold in the auction or sealed bid process. No assurance can be given that ECA would make a bid in any such process. However, in the event that ECA were to bid in any such process and were the top bidder, ECA would be entitled to purchase the Royalty NPI to be sold in the auction or sealed bid process. Any such purchase pursuant to the auction or sealed bid process by ECA or a third party could be at a price lower than fair value.

As used in the foregoing discussion, the term "fair value" has the meaning ascribed to it in the Trust Agreement, which means an amount which could reasonably be expected to be obtained from the sale of the asset to a party which is not an affiliate of either ECA or the Trust on an arms'-length negotiated basis, taking into account relevant market conditions and factors existing at the time of the proposed sale.

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.

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 June 30, 2012. At June 30, 2012, the Trust had Trust General and Administrative Expenses Payable of $141,763 and Distributions Payable of $797,457.

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

The Trust's Distributable Income was $797,457 for the three months ended June 30, 2012 as compared to $1,586,758 for the three months ended June 30, 2011. This decrease was due to a decrease in Royalty Income of $643,666 ($1,268,807 for the three months ended June 30, 2012 as compared to $1,912,473 for the three months ended June 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 ($3.190 per Mcf for the three months ended June 30, 2012 as compared to $5.105 per Mcf for the three months ended June 30, 2011). Offsetting this decrease was an increase in production of gas attributable to the Net Profits Interests for the three months ended June 30, 2012 (398 MMcf) as compared to the three months ended June 30, 2011 of (374 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 $96,881 for the three months ended June 30, 2012 as compared to $135,191 for the three months ended June 30, 2011. The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $224,595 for the three months ended June 30, 2012 as compared to $229,430 for the three months ended June 30, 2011. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees.

The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.190 per Mcf for the three months ended June 30, 2012 and $5.105 per Mcf for the three months ended June 30, 2011. The price per Mcf was lower for the three months ended June 30, 2012 than for the corresponding three month period ended June 30, 2011 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.600 per million British Thermal Units ("Dth") for the three months ended June 30, 2012 as compared to $4.341 per Dth for the three months ended June 30, 2011).


Financial results depend on many factors, particularly the price of natural gas. During the second quarter of 2012, the Trust experienced a significant decrease in natural gas prices from the prior year. Price variations may have a material impact on the financial statements.

Comparison of Results of Operations for Six Months Ended June 30, 2012 and Six Months Ended June 30, 2011

The Trust's Distributable Income was $1,657,342 for the six months ended June 30, 2012 as compared to $2,639,372 for the six months ended June 30, 2011. This decrease was due to a decrease in Royalty Income of $890,968 ($2,767,507 for the six months ended June 30, 2012 as compared to $3,658,475 for the six months ended June 30, 2011). The decrease in Royalty Income was due to a decrease in the price payable to the Trust under the Gas Purchase Contract as discussed below ($3.517 per Mcf for the six months ended June 30, 2012 as compared to $4.976 per Mcf for the six months ended June 30, 2011). Offsetting this decrease was an increase in production of gas attributable to the Net Profits Interests for the six months ended June 30, 2012 (789 MMcf) as compared to the six months ended June 30, 2011 (735 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 $207,977 for the six months ended June 30, 2012 as compared to $258,048 for the six months ended June 30, 2011. The decrease in taxes is due directly to the decrease in Royalty Income as discussed above. General and Administrative Expenses were $602,434 for the six months ended June 30, 2012 as compared to $635,310 for the six months ended June 30, 2011. The decrease in General and Administrative Expenses was due primarily to a decrease in professional fees.

The price payable to the Trust for gas production attributable to the Net Profits Interests was $3.517 per Mcf for the six months ended June 30, 2012 and $4.976 per Mcf for the six months ended June 30, 2011. The price per Mcf was lower for the six months ended June 30, 2012 than for the corresponding six month period ended June 30, 2011 due to a decrease in the average spot market price for gas delivered at the Henry Hub near Henry, Louisiana ($2.898 per Dth for the six months ended June 30, 2012 as compared to $4.224 per Dth for the six months ended June 30, 2011).

Financial results depend on many factors, particularly the price of natural gas. During the six months ended June 30, 2012, the Trust experienced a significant decrease in natural gas prices from the prior year. Price variations may have a material impact on the financial statements.

The Trust has incurred expenses in preparation for its sale of the Royalty NPI and liquidation and expects to incur substantial additional expenses in connection with its sale of the Royalty NPI and liquidation between July 1, 2012 and May 15, 2013.

Off-Balance Sheet Arrangements

The Trust does not have any off-balance sheet arrangements that have or are . . .

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