10-Q 1 baycorp10q3312005.txt BAYCORP HOLDINGS, LTD. 1ST QUARTER 2005 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark one) [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2005 or [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to _____________ Commission file number 1-12527 BAYCORP HOLDINGS, LTD. (Exact name of registrant as specified in its charter) ---------------------------------------------------- Delaware 02-0488443 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1 New Hampshire Avenue, Suite 125 03801 Portsmouth, New Hampshire (Address of principal executive (Zip Code) offices) Registrant's telephone number, including area code: (603) 766-4990 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act.) Yes No X --- --- Class Outstanding at April 30, 2005 ------------------------------ --------------------------- Common Stock, $0.01 Par Value 557,945 per Share

INDEX PART I - FINANCIAL INFORMATION: Item 1 - Financial Statements: Consolidated Statements of Operations - Three ~~and Six~~ Months Ended ~~June~~March 3031, ~~2004~~2005 and ~~2003~~2004 . . . . . . . . . . . . . . . . 3 Consolidated Balance Sheets at ~~June~~March 3031, ~~2004~~2005 and December 31,~~2003~~ 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Consolidated Statements of Cash Flows - ~~Six~~Three Months Ended ~~June~~March 3031, ~~2004~~2005 and ~~2003~~2004 . . . . . . . . . . . . . . . . 5 Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . 6 Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . ~~12 Item 3 - Quantitative and Qualitative Disclosures About Market Risk~~ . . . . . . . . . . . . .15 .Item .3 .- .Quantitative and Qualitative Disclosures About Market Risk . . . . 1927 Item 4 - Controls and Procedures . . . . . . . . . . . . . . . 20. . . . . . . 28 PART II - OTHER INFORMATION: Item 2 - ~~Changes~~Unregistered inSales of Equity Securities and Use of Proceeds . . . .29 ~~. . 21~~ Item 36 - ~~Defaults~~Exhibits ~~Upon Senior Securities~~ . . . . . . . . . . . ~~21 Item 4 - Submission of Matters to a Vote of Security Holders~~ . ~~21 Item 5 - Other Information~~ . . . . . . . . . . . . . . . . . .29 22Signatures ~~Item~~. 6. ~~- Exhibits and Reports on Form 8-K~~ . . . . . . . . . . ~~22 Signatures~~ . . . . . . . . . . . . . . . . . . . . 30 Exhibit Index . . . . . . ~~23 Exhibit Index~~ . . . . . . . . . . . . . . . . . . . . . . . . . 2431

2 PART I - FINANCIAL INFORMATION Item 1. Financial Statements ----------------------------

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (Dollars in thousands except per share data) Three Months Ended ~~Six~~March ~~Months Ended June 30~~31, ~~June~~2005 ~~30,~~ 2004 ~~2003 2004 2003~~ ---- ---- ~~---- ----~~ Operating Revenues $~~1,443 $996 $~~2,~~477~~360 $1,~~987~~034 Operating Expenses Purchased Power ~~998 902 2~~1,~~129~~198 21,~~097~~131 Unrealized Loss ~~(Gain)~~ on Energy Contracts ~~716~~1,989 ~~(498) 2~~1,~~353~~637 ~~585~~Production and Transmission 211 0 Administrative & General ~~625~~727 ~~909~~415 1Depreciation,~~052~~ ~~1,793~~Depletion ~~--------~~and ~~--------~~Amortization 270 0 Taxes Other Than Income 60 13 -------- -------- Total Operating Expenses 24,~~339~~455 13,~~313~~196 ~~5,534 4,475~~ Operating Loss (~~896) (317) (3~~2,~~057~~095) (2,~~488~~162) Other Income Interest and Dividend Income 4442 3255 ~~99 434~~ Other Income ~~667~~44 ~~320~~9 ~~676 327~~ -------- -------- ~~-------- --------~~ Total Other Income ~~711~~86 ~~352~~64 ~~775 761 Income (Loss) Before Income Taxes, Minority Interest~~ --------- -------- ~~--------~~Loss ~~--------~~Before ~~and~~Income ~~Extraordinary~~Taxes ~~Item~~and ~~(185)~~Minority 35Interest (2,~~282~~009) (12,~~727~~098) Income Taxes 0225 0 ~~0 0~~ Minority Interest ~~Income 2 0 2 0 -------- -------- -------- -------- Income~~ (~~Loss~~20) ~~Before Extraordinary Item (183) 35 (2,280) (1,727) Extraordinary Item, Net of Income Tax 278~~ 0 ~~278 0~~ -------- -------- ~~-------- --------~~ Net ~~Income (~~Loss) ~~$95 $35~~ ($21,~~002~~804) ($12,~~727~~098) ======== ======== ~~======== ========~~ Weighted Average Shares Outstanding - Basic ~~592,833~~and ~~646~~557,~~917~~945 ~~611~~629,~~093~~353 ~~4,225,628 Weighted Average Shares Outstanding -~~ Diluted ~~592,833~~Net ~~653,357 611,093 4,225,628 Income (~~Loss) Per Share ~~before Extraordinary Item~~ - Basic ~~($0.31)~~and ~~$0.05 ($3.73) ($0.41) Income (Loss) Per Share before Extraordinary Item -~~ Diluted ($~~0.31) $0.05 ($~~3.7323) ($~~0.41) Extraordinary Item Income Per Share - Basic $0.47 - $0.45 - Extraordinary Item Income Per Share - Diluted $0.47 - $0.45 - Net Income (Loss) Per Share - Basic $0.16 $0.05 ($~~3.2833) ~~($0.41) Net Income (Loss) Per Share - Diluted $0.16 $0.05 ($3.28) ($0.41) (The accompanying notes are an integral part of these consolidated statements.)~~

(The accompanying notes are an integral part of these consolidated statements.) 3

~~June~~CONSOLIDATED 30BALANCE SHEETS (UNAUDITED) (Dollars in thousands except per share data) March 31, December 31, 2005 2004 ~~2003~~ ---------- --------~~----~~ ASSETS Current Assets: Cash & Cash Equivalents $68,~~943~~093 $79,~~469~~627 ~~Restricted Cash - Escrow 2,500 2,500~~ Accounts Receivable, net ~~799~~1,284 ~~339~~639 Prepayments & Other Assets ~~145~~49 ~~1,085~~83 -------- -------- Total Current Assets 109,~~387~~426 1110,~~393~~349 Other Long Term Assets: ~~Unrealized~~Restricted ~~Gain~~Cash on- ~~Energy~~Escrow ~~Contract~~2,936 -2,500 atIntangible ~~market~~Asset -45 345 Gas and Oil Properties, Net 9,305 670 Property, Plant and Equipment, net 2,129 0 Other Long Term Assets ~~1,264~~520 ~~1,508~~518 -------- -------- Total Other Assets 114,~~264~~935 13,~~511~~733 TOTAL ASSETS $1124,~~651~~361 $1214,~~904~~082 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts Payable and Accrued Expenses $~~1,118~~705 $~~965~~769 Accrued Taxes 8289 9592 ~~Miscellaneous~~Note Payable 10,286 0 Other Current Liabilities ~~802~~552 ~~1,740~~741 -------- -------- Total Current Liabilities 211,~~002~~632 21,~~800~~602 Deferred Gain on Energy Contract 1,~~666~~469 1,~~798~~534 Unrealized Loss on Energy Contract - at market 5,478 3,424 Long Term Liability 2,~~481~~480 -2,479 Minority Interest in Subsidiary ~~186~~239 -219 Commitments & Contingencies Stockholders' Equity: Preferred stock, $.01 par value Authorized - 1,000,000 shares - - Issued and Outstanding - 0 shares Common stock, $.01 par value Authorized - 4,000,000 shares Issued and Outstanding - ~~560~~557,~~096~~945 shares 6 6 ~~and 641,937 shares, respectively~~ Additional Paid-in Capital (21,~~519~~431) (2021,~~531~~475) Accumulated Earnings 2624,~~829~~488 2826,~~831~~293 -------- -------- Total Stockholders' Equity 53,~~316~~063 84,~~306~~824 TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $1124,~~651~~361 $1214,~~904~~082 ======== ========

(The accompanying notes are an integral part of these consolidated statements.) 4

~~Six~~CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (Dollars in thousands) Three Months Ended ~~June~~March 3031, 2005 2004 ~~2003~~ ---- ---- Net cash flow from operating activities: Net loss ($21,~~002~~804) ($12,~~727~~098) Adjustments to reconcile net loss to net cash used in operating activities: Minority ~~Interest~~interest ~~Income~~expense ~~(2)~~20 -0 ~~Extraordinary gain, net of income tax (278) -~~ Unrealized loss on the mark-to-market of energy contract 2,~~485~~054 ~~716~~1,703 Amortization of deferred gain on energy contract (~~132~~65) (~~131~~66) Non-cash compensation expense 8643 ~~296~~43 Depreciation, depletion and amortization 270 0 Increase in accounts receivable (~~366~~642) ~~(12)~~0 (Increase) ~~decrease~~ in prepaids and other assets ~~1,220~~(404) ~~256 Increase~~ (~~decrease~~98) Decrease in accounts payable and accrued expenses ~~110~~(66) ~~452~~(97) Decrease in taxes accrued (3) (13) 0 Decrease in miscellaneous and other liabilities (~~953~~153) (~~4,283~~16) ------- -------- Net cash ~~provided by (~~used in) operating activities ~~155~~(750) (~~4,433~~642) Net cash provided by investing activities: ~~Consolidation~~Increase ofin ~~HoustonStreet~~fixed ~~393~~assets -(2,129) 0 Investment in oil and gas properties (8,905) 0 ------- -------- Net cash ~~provided~~used byin investing activities ~~393~~(11,034) -0 Net cash used in financing activities: ~~Stock~~Convertible ~~option~~note ~~exercise~~10,250 0 ~~1,776~~ Reacquired capital stock and options ~~(1,074)~~0 (~~123,622~~395) ------- -------- Net cash provided by (used in) financing activities (110,~~074)~~250 (~~121,846~~395) Net decrease in cash and cash equivalents (~~526~~1,534) (~~126~~1,~~279~~037) Cash and cash equivalents, beginning of period 9,627 7,469 ~~134,164~~ ------- -------- Cash and cash equivalents, end of period $68,~~943~~093 $76,~~885~~432 ======= ======== Supplemental disclosure of ~~non-~~cash ~~financing~~flow ~~activities~~information: Cash paid during the period for income taxes $12 27 $~~2,241~~ 12 -------- --------

(The accompanying notes are an integral part of these consolidated statements.) 5 NOTES TO FINANCIAL STATEMENTS NOTE A - THE COMPANY BayCorp Holdings, Ltd. ("BayCorp" or the "Company") is an unregulated holding company incorporated in Delaware in 1996. As of March 31, 2005, BayCorp had six wholly owned subsidiaries including Great Bay Power Marketing, Inc., Great Bay Hydro Corporation, Nacogdoches Power, LLC, Nacogdoches Gas, LLC, Great Bay Hydro Maine, LLC. and BayCorp Ventures, LLC. BayCorp also held a majority interest in HoustonStreet Exchange, Inc. as of March 31, 2005. Until January 1, 2003, BayCorp had two principal operating subsidiaries that generated and traded wholesale electricity, Great Bay Power Corporation ("Great Bay") and Little Bay Power Corporation ("Little Bay"). Their principal asset was a combined 15% joint ownership interest in the Seabrook Nuclear Power Project in Seabrook, New Hampshire (the "Seabrook Project" or "Seabrook") until November 1, 2002, when BayCorp sold Great Bay's and Little Bay's interest in Seabrook. That ownership interest entitled Great Bay and Little Bay to approximately 174 megawatts ("MWs") of the Seabrook Project's power output. In December 2002, BayCorp dissolved Great Bay and Little Bay. Great Bay Power Marketing, Inc. ("Great Bay Power Marketing"), incorporated in Maine as a wholly owned subsidiary, was created to hold the purchased power agreement that Great Bay had with Unitil Power Corporation ("Unitil") and to arrange for the power supply to satisfy the agreement. Effective January 1, 2003, Great Bay Power Marketing assumed the Unitil contract and holds the letter of credit established to secure Great Bay Power Marketing's obligations under the Unitil contract. BayCorp formed BayCorp Ventures, a Delaware limited liability company, as a wholly owned subsidiary, to serve as a vehicle through which the Company can make investments. In September 2003, BayCorp formed Great Bay Hydro Corporation ("Great Bay Hydro"), a New Hampshire corporation, as a wholly owned subsidiary. Great Bay Hydro entered into a purchase and sale agreement, dated as of October 30, 2003, with Citizens Communications Company ("Citizens") to acquire the generating facilities in Vermont owned by the Vermont Electric Division of Citizens. Great Bay Hydro completed the acquisition and assumed operating responsibility of the generating facilities on April 1, 2004. The generating facilities include an operating hydroelectric facility of approximately 4 megawatts located in Newport, Vermont, diesel engine generators totaling approximately 7 megawatts located in Newport, Vermont and non-operating hydroelectric facilities in Troy and West Charleston, Vermont. In October 2004, BayCorp formed Nacogdoches Power, LLC ("Nacogdoches Power"), a New Hampshire limited liability company, as a wholly owned subsidiary. On October 19, 2004, Nacogdoches Power acquired the development rights to an approximate 1000 MW natural gas-fired power plant project in Nacogdoches County, Texas, located in east Texas. The project received its air quality permit and its wastewater discharge permit and has options to acquire the land and a number of easements for the plant. The proposed plant site is located near the Electric Reliability Council of Texas ("ERCOT") and the Southwest Power Pool high voltage transmission lines as well as a source of cooling water and natural gas lines. Nacogdoches Power is pursuing the development of this project with an initial focus on securing gas supply and power offtake contracts. In November 2004, BayCorp formed Nacogdoches Gas, LLC ("Nacogdoches Gas"), a New Hampshire limited liability company, as a wholly owned subsidiary. In the fourth quarter of 2004 Nacogdoches Gas entered into agreements with Sonerra Resources Corporation ("Sonerra"), an independent oil and gas exploration, development and operating company, under which Nacogdoches Gas acquired an approximate 10% working interest (of a 77% net revenue interest) in two natural gas and oil producing wells. Nacogdoches Gas entered into an agreement, dated January 7, 2005 with Sonerra, under which Nacogdoches Gas will fund the development of three natural gas and oil wells. This agreement was amended as of March 14, 2005, increasing the number of wells from three to four. In addition, Nacogdoches Gas has an option to participate in Sonerra's continued development of up to 15 additional natural gas and oil wells over the next two years. Under the agreement with Sonerra, Nacogdoches Gas will receive a priority return until its aggregate investment is recovered. Since entering the January 7, 2005 agreement with Sonerra, Nacogdoches Gas has 6 funded the development of four wells. The net revenue interest in each of these four wells being funded by Nacogdoches Gas is 77% with the remaining 23% of the net revenues paid to the lessor and other royalty interests. Nacogdoches Gas has a 90% ownership percentage in each of these wells and a 100% cost percentage. This means that Nacogdoches Gas has a working interest that bears 100% of the operating costs of the wells and receives 69.3% of the net revenues from the wells. The first of those wells, Round Mountain, a James Lime horizontal natural gas well, began production in January 2005 and through the end of March 2005 has produced 134 million cubic feet of natural gas. The second well, Wicked Wolf, a James Lime horizontal natural gas well, began production in early March 2005 and through the end of march 2005 has produced approximately 73 million cubic feet of natural gas. The third and fourth wells, Painted Horse, a Rodessa vertical natural gas well, and Whirlwind, a James Lime horizontal natural gas well, are being developed. In April 2005, Nacogdoches Gas funded the acquisition of certain natural gas production assets in Nacogdoches County, Texas formerly owned by SunStone Corporation ("SunStone") for approximately $3.4 million. The assets include:

~~Four~~Working ~~Months~~Net ~~ended~~Revenue ~~Six~~Overriding ~~Months~~Well ~~ended~~Name ~~HoustonStreet:~~Interest ~~April~~Interest ~~30,~~Royalty ~~2004~~Interest ~~June 30, 2003~~ --------- ----- --- ----------- --------------- ~~(Dollars~~Kendrick #1-H 25.1 % 19.3 % 1.7 % Sitting Bull #1 25.1 % 19.3 % 1.3 % Crazy Horse #1 0.0 % 0.0 % 1.5 % Soaring Eagle #1 29.2 % 22.4 % 1.1 % Ten Bears #1 37.8 % 29.1 % 0.4 % Ten Bears #2 0.0 % 0.0 % 0.9 % Sky Chief #1 25.1 %* 19.3 %* 2.4 % *This is a back in ~~Thousands)~~interest ~~Revenues~~that $will ~~224~~be ~~$467~~acquired ~~Gross~~after ~~Loss~~the ~~(123)~~recovery ~~(23)~~of ~~Net~~a ~~Income~~300% ~~(Loss)~~non- ~~13,318~~consent ~~(582)~~penalty.

- A 75.6% ownership interest in 3D seismic survey data that covers approximately 49 square miles in Nacogdoches County. - A 37.8% undivided leasehold interest in approximately 3,800 acres within the area covered by the 3D seismic survey data. - Undivided interests in the Melrose Gas Gathering Pipeline System (the "Melrose System"), located within the Kendrick (James Lime) Field, Nacogdoches County, Texas, consisting of: (i) an undivided 25% interest in the section of the Melrose System originating at mile-post 207.68 marker as a 6" tap in the Texas Eastern line, and extending West through a 6" pipeline to the Sonerra, Kendrick No. 1-H well, (ii) an undivided 29.1552% interest in the section of the Melrose System occurring from the Kendrick No.1 well and extending as a 6" pipeline to the Sonerra, Soaring Eagle No.1 well and (iii) an undivided interest in all rights of way, equipment and appurtenances relating to such segments, and including all facilities and equipment presently existing at and associated with the Texas Eastern tap site and facility. 7 Nacogdoches Gas acquired these assets in accordance with the terms of the January 7, 2005 agreement with Sonerra and the Acquisition Agreement dated as of March 22, 2005 among Sonerra, Pinnacle Energy Group, L.C. and Nacogdoches Gas. Under its agreement with Sonerra, Nacogdoches Gas will have a 90% interest and Sonerra will have a 10% interest in these assets until 110% of the $3.4 million purchase price of the SunStone assets and all of the funding provided by Nacogdoches Gas for wells drilled under the January 7, 2005 agreement is recovered. Once Nacogdoches Gas recovers its investment and other operating costs, its interest in all assets will become 50% and Sonerra will own the other 50%. In March 2005, BayCorp formed Great Bay Hydro Maine, LLC ("GBH Maine"), a Maine limited liability company, as a wholly owned subsidiary, and formed Great Bay Hydro Benton, LLC ("GBH Benton"), also a Maine limited liability company, as a wholly owned subsidiary of GBH Maine. On March 16, 2005, GBH Maine and GBH Benton acquired Benton Falls Associates, L.P., a limited partnership that owns a 4.3 megawatt hydroelectric generation plant in Benton, Maine ("Benton Falls"), from The Arcadia Companies for approximately $2.2 million. The purchase of Benton Falls was accounted for under the purchase method of accounting and the purchase price was allocated to fixed assets. The Company assumed operating responsibility for Benton Falls, the output of which is sold to Central Maine Power Corporation ("CMP") under a power purchase agreement ("CMP PPA") that expires in December 2007. The rates under the CMP PPA are indexed to CMP's standard rates for energy and capacity purchases established annually by the Maine Public Utilities Commission. The estimated average rate for April 2005 through December 2005 (based on projected monthly generation) is approximately $59.12 per megawatt hour ("MWh".) The results of operations of Benton Falls are included in the Company's financial statements as of the date of acquisition. BayCorp also owns shares representing approximately 59.7% of the outstanding common shares of HoustonStreet Exchange, Inc. ("HoustonStreet"), which was incorporated in Delaware in 1999. HoustonStreet developed and operates HoustonStreet.com, an Internet-based independent crude oil and refined products trading exchange in the United States. A recapitalization of HoustonStreet was completed in the second quarter of 2004, and as a result, BayCorp's ownership interest in HoustonStreet increased above 50% and BayCorp began consolidating its financial statements with HoustonStreet as of May 1, 2004. Prior to May 1, 2004, BayCorp held a minority interest in HoustonStreet and accounted for HoustonStreet under the equity method. Sale of Seabrook Ownership -------------------------- In April 2002, FPL Energy Seabrook, LLC ("FPL Energy Seabrook"), a subsidiary of FPL Group, Inc., agreed to purchase 88.2% of the 1,161 MW Unit 1 and 88.2% of the partially constructed Unit 2 of Seabrook, for $836.6 million, which included Great Bay's and Little Bay's approximate aggregate 15% ownership share, subject to certain adjustments, with payment deliverable fully in cash at closing. FPL Energy Seabrook assumed nearly all of the Company's Seabrook liabilities including the decommissioning liability for the acquired portion of Seabrook. On November 1, 2002, the Company closed the sale of its interests in Seabrook and received approximately $113 million in cash for its interests in the Seabrook Project (the "Seabrook Closing"). NOTE B - DEBT FINANCING On March 15, 2005, the Company and all of its wholly owned subsidiaries entered into a $10,250,000 Convertible Note (the "Note") and a Pledge Agreement (the "Pledge Agreement") with Sloan Group Ltd., a Bahamas corporation (the "Sloan Group"). The debt, which accrues interest at 8% per annum and is due and payable in full on December 15, 2005, is convertible by 8 the Sloan Group at any time between November 15, 2005 and December 15, 2005 (or any time after the occurrence and during the continuance of a material event of default under the Note) into shares of BayCorp's common stock, $.01 par value at a price of $14.04 per share. The Note does not allow BayCorp to prepay the debt and provides for a 2% premium on the interest rate in the event of a default. Payment of the Note may be accelerated in the event of a material event of default. In addition to BayCorp, the borrowers under the Note include the following subsidiaries of BayCorp: GBH Maine, GBH Benton, Great Bay Power Marketing, Great Bay Hydro, BayCorp Ventures, Nacogdoches Power and Nacogdoches Gas. As security for the Note, the borrowers entered into the Pledge Agreement with the Sloan Group. Under the Pledge Agreement, BayCorp pledged its equity interests in GBH Maine and Nacogdoches Gas to the Sloan Group, GBH Maine pledged its equity interests in GBH Benton and Benton Falls to the Sloan Group, GBH Benton pledged its equity interests in Benton Falls to the Sloan Group, and Nacogdoches Gas, GBH Maine and GBH Benton pledged to the Sloan Group any equity interest that they may obtain in other entities while the debt is outstanding. NOTE C - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The unaudited financial statements included herein have been prepared on behalf of the Company pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and include, in the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of interim period results. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted or condensed pursuant to such rules and regulations. The Company believes, however, its disclosures herein, when read in conjunction with the Company's audited financial statements for the year ended December 31, 2004 as filed in Form 10-K on March 31, 2005, are adequate to make the information presented not misleading. The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in the Company's 10-K. The results for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. Principles of Consolidation BayCorp's Consolidated Financial Statements include the accounts of the Company and all its subsidiaries. In November 2004, BayCorp formed Nacogdoches Gas, which acquired an approximate 10% working interest in two natural gas and oil producing wells in the fourth quarter of 2004. The Company records in its financial statements its proportional share of well revenues and expenses. The Company consolidates all majority-owned and controlled subsidiaries and applies the equity method of accounting for investments between 20% and 50%. All significant intercompany transactions have been eliminated. All sales of subsidiary stock are accounted for as capital transactions in the consolidated financial statements. In January 2003, the FASB issued Interpretation No. ("FIN") 46, Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51, as amended by FIN 46R. The interpretation requires that a company consolidate the financial statements of an entity that cannot finance its activities without outside financial support, and for which that company provides the majority of support. The Company deemed that its investment, HoustonStreet , was not a variable interest entity. Therefore, prior to May 1, 2004 and when BayCorp held a minority interest in HoustonStreet, the Company accounted for HoustonStreet under the equity method. A recapitalization of HoustonStreet was completed effective May 1, 2004, and as a result, BayCorp's ownership interest in HoustonStreet increased above 50%. As a result of this recapitalization, BayCorp began consolidating HoustonStreet as of May 1, 2004. 9 Energy Marketing Forward contracts (including the Unitil PPA) meeting the definition of a derivative and not designated and qualifying for the normal purchases and normal sales exception or as a hedge under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) are recorded at fair value with changes in fair value recorded in earnings. In accordance with FASB's Emerging Issues Task Force Issue No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF Issue No. 02-03), revenues related to derivative instruments classified as trading are reported net of related cost of sales. Stock Based Compensation The Company accounts for its stock option plans in accordance with SFAS No. 123, "Accounting for Stock Based Compensation." Awards under the Company's plans vest over periods ranging from one to three years. The Company recorded compensation expense of $43,000 in the three months ended March 31, 2005 and 2004 based on the fair value of options granted determined using the Black- Scholes option pricing model. Depletion of Oil and Gas Properties The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such impairment is charged to expense in that period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and geological and geophysical expenses, are expensed as incurred. The provision for depletion is based upon the units of production method. Asset Retirement Obligation The Company has adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long- lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. The estimated liability is based upon historical experience in plugging and abandoning wells, estimated remaining lives of those wells, estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk- free interest rate or remaining lives of the wells, or if federal of state regulators enact new plugging and abandonment requirements. NOTE D - COMMITMENTS AND CONTINGENCIES 10 Purchased Power Agreements -------------------------- Great Bay was party to a purchased power contract, dated as of April 1, 1993, (the "Unitil PPA" or "PPA"), with Unitil that provided for Great Bay to sell to Unitil 0.8696% of the energy and capacity of Seabrook, or approximately 10 MWs. The Unitil PPA commenced on May 1, 1993 and continues through October 31, 2010. On November first of each year the purchase price is subject to increase at the rate of inflation less four percent. In anticipation of the Seabrook sale, the Unitil PPA was amended as of November 1, 2002. The amendment primarily modified the existing Unitil PPA to reduce the amount of power delivered to 9.06 MWs and the price that Unitil pays for power to $50.34 per MW hour, subject to an annual increase at the rate of inflation less four percent, and provided that Great Bay would supply the power regardless of whether Seabrook is providing the power. The amendment also provided alternative security for Unitil's benefit, to replace and discharge the mortgage on Seabrook that secured Great Bay's performance of the Unitil PPA. In connection with the amended Unitil PPA, the Company was required to deposit $2.5 million into a restricted account for the benefit of Unitil should Great Bay default. The amount is reflected as restricted cash in the accompanying balance sheet. The amendment received FERC approval. Great Bay assigned the Unitil PPA to Great Bay Power Marketing as of January 1, 2003. Unitil has an option, expiring November 1, 2005, to extend the Unitil PPA for up to 12 years, until 2022. If Unitil exercises its option to extend the PPA, the purchase price for power for the first year of the extended term, beginning November 1, 2010, will be $65.00 per MW hour (in 1992 dollars) multiplied by a factor that equals the cumulative inflation from October 1992 through October 2010. For the remaining term of the extension, the purchase price will be increased annually by the rate of inflation over the previous year. Forward contracts (including the Unitil PPA) meeting the definition of a derivative and not designated and qualifying for the normal purchases and normal sales exception under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) are recorded at fair value. In accordance with the FASB's EITF issue no. 02-03 the inception gain (initial value of $2.1 million) on the Unitil PPA has been deferred and will be recognized over the life of the contract. The fair value of the contract was a negative $5.5 million as of March 31, 2005 and was negative $3.4 million as of December 31, 2004. The deferred gain on the contract was $1.5 million as of March 31, 2005 and as of December 31, 2004. These amounts are reflected in the Company's balance sheet. On March 17, 2003, Unitil announced the approval of a contract with Mirant Americas Energy Marketing, LP ("Mirant"), which provided for the sale of Unitil's existing power supply entitlements, including the PPA with Great Bay Power Marketing, effective on May 1, 2003. Great Bay Power Marketing's PPA with Unitil has not been assigned to Mirant. Rather, Unitil has appointed Mirant as their agent for purposes of administering the PPA with Great Bay Power Marketing and Mirant is purchasing Unitil's entitlement under the PPA. NOTE E - OIL AND GAS ACTIVITIES The following summarizes selected information with respect to oil and gas producing activities. 11 Quarter ended March 31, 2005 --------------- ( in thousands) Oil and Gas properties: Properties subject to depletion $6,447 Unproved properties 2,260 ------ Total 8,707 Accumulated depletion 290 ------ Net $8,417 ====== The Company's proved oil and gas reserves are located in the United States. The following schedule is presented in accordance with SFAS No. 69 ("SFAS 69"), "Disclosures about Oil and Gas Producing Activities," to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Reserves of crude oil, condensate, natural gas liquids and natural gas are estimated by engineering consultants and are adjusted to reflect contractual agreements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered as a result of additional investments for drilling new wells to offset productive units, recompleting existing wells, and/or installing facilities to collect and transport production. Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, and especially in the case of natural gas, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids. Quantities of Proved Natural Gas Reserves (Mmcf): Balance December 31, 2004 149 Revisions 0 Extensions, discoveries and additions 0 Purchases 3,580 Sales 0 Production (152) -------- Balance, March 31, 2005 3,577 NOTE F - INVESTMENT IN HOUSTONSTREET BayCorp owns shares representing approximately 59.7% of the voting power of all outstanding common shares of HoustonStreet. HoustonStreet developed and operates HoustonStreet.com, an Internet-based, independent crude oil and refined products trading exchange in the United States. 12 Prior to April 30, 2004, in addition to its equity interest in HoustonStreet, the Company held an $8.4 million secured note in HoustonStreet. In March 2001, HoustonStreet raised additional funding by selling senior secured notes to BayCorp and other investors. Collectively, these notes were referred to as the "HoustonStreet Series C Units." The outstanding principal and interest of the note to BayCorp as of April 30, 2004 was approximately $11 million. The Company had written this note down to zero as of December 31, 2000. The notes were originally due and payable in December 2001, and the maturity date was subsequently extended to January 15, 2004. The notes were not paid when due, and in February 2004, HoustonStreet was formally notified of the payment default. BayCorp and the other senior secured noteholders reserved their rights and proposed a recapitalization of HoustonStreet that would potentially provide effective control of HoustonStreet to the noteholders. The recapitalization was approved by the Board of Directors of HoustonStreet in March 2004 and was approved by HoustonStreet shareholders in April 2004. The effect of the recapitalization was to convert HoustonStreet's secured debt into equity and convert outstanding preferred stock in HoustonStreet into either the right to receive nominal cash consideration or a nominal amount of HoustonStreet common stock. All outstanding shares of HoustonStreet common stock prior to the restructuring were cancelled. As a result of the restructuring, as of May 1, 2004, holders of senior secured promissory notes held common stock of HoustonStreet representing approximately ninety-nine percent of the outstanding capital stock of HoustonStreet. Holders of preferred stock held approximately one percent of the outstanding capital stock as a result of the restructuring. This recapitalization at HoustonStreet was completed in the second quarter of 2004 and as a result, BayCorp owns shares representing approximately 59.7% of the outstanding common shares of HoustonStreet In accordance with EITF Topic D-84, the Company followed step acquisition accounting to consolidate HoustonStreet. The fair value of current assets exceeded BayCorp's net investment in HoustonStreet by $278,000 resulting in negative goodwill upon application of step acquisition accounting. As a result, the Company recognized an extraordinary gain of $278,000 in the second quarter of 2004 in accordance with SFAS No. 141 "Business Combinations." Prior to the recapitalization, BayCorp held a minority ownership interest in HoustonStreet and accounted for HoustonStreet under the equity method. Summarized financial information for HoustonStreet, prior to consolidation, is as follows: HoustonStreet: March 31, 2004 -------------- -------------- Total Assets $ 564 Total Liabilities 13,835 Net Sales 168 Net Income (Loss) (342) Company's equity in Net Income (170) NOTE G - EQUITY On January 31, 2003, BayCorp commenced an issuer tender offer to purchase up to 8,500,000 shares of its common stock at a price of $14.85 per share (the "Tender Offer" or "Offer"). At the extended Tender Offer expiration date of March 18, 2003, 9,207,508 shares had been properly tendered and not withdrawn (including options surrendered for repurchase and cancellation.) The Company exercised its discretion to purchase up to an additional 2% of outstanding shares, purchasing a total of 8,673,887 shares (and surrendered options) at a purchase price of $14.85, representing approximately 94.3% of the shares (and options) tendered, excluding odd lots, which were purchased without proration. Payment for all such shares and options was completed by March 24, 2003. The 13 Company distributed approximately $123,622,000 to tendering stockholders and option holders. As of March 31, 2005 there were 557,945 shares outstanding and options to purchase 212,538 shares, 170,038 of which were exercisable. BayCorp has never paid cash dividends on its common stock. Any future dividends depend on future earnings, BayCorp's financial condition and other factors. NOTE H - SEGMENT INFORMATION The Company has adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS No. 131 establishes standards for the reporting of information about operating segments in annual and interim financial statements. Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker(s) in deciding how to allocate resources and in assessing performance. SFAS No. 131 also requires disclosures about products and services, geographic areas and major customers. BayCorp is a holding company for Great Bay Power Marketing, Great Bay Hydro, BayCorp Ventures, Nacogdoches Power, Nacogdoches Gas, Great Bay Hydro Maine and HoustonStreet. The Company operates primarily in three segments, each of which is managed separately because each segment sells distinct products and services. Great Bay Power Marketing, Great Bay Hydro and Great Bay Hydro Maine constitute the electricity generation and trading business segment, whose principal assets are the Unitil PPA and hydroelectric facilities of approximately 4 megawatts located in Newport, Vermont, diesel engine generators totaling approximately 7 megawatts located in Newport, Vermont and non-operating hydroelectric facilities in Troy and West Charleston, Vermont and a 4.3 megawatt hydroelectric generation plant in Benton, Maine. Nacogdoches Gas constitutes the oil and gas production and sales segment, whose principal assets are its interests in oil and gas wells in East Texas. HoustonStreet, representing the crude oil and refined products trading exchange segment, developed and operates HoustonStreet.com, an Internet-based independent crude oil and refined products trading exchange in the United States. Management utilizes more than one measurement and multiple views of data to measure segment performance and to allocate resources to the segments. However, the dominant measurements are consistent with the company's consolidated financial statements and, accordingly, are reported on the same basis herein. Management evaluates the performance of its segments and allocates resources to them primarily based on cash flows and overall economic returns. 14

~~6/30/04~~BayCorp ~~6/30/03~~Holdings, ~~-------~~Ltd ~~------- Net Loss:~~ As ~~Reported~~of ~~($2,002)~~and ~~($1,727)~~for ~~Stock~~the ~~compensation~~Electricity ~~expense~~Oil ~~included~~and inthree ~~net~~months ~~loss~~ended 86Generation ~~296~~Gas ~~Stock~~Houston- ~~compensation~~Inter- ~~expense~~March ~~determined~~31 ~~using~~and ~~fair~~Produc- ~~value~~Street ~~method~~company ~~for~~($000's) ~~all~~Trading ~~awards~~tion (861) ~~(237)~~Other Elim Total -------- --------------------------------------------------------------------------------------- ~~Pro~~2005 ~~Forma~~---- .Revenues .$1,186 .$931 .$243 .$0 .$0 .$2,360 .Operating .Expenses .3,514 .534 .201 485 (~~$2,002~~279) ~~($1~~4,~~668)~~455 ~~Loss~~Segment ~~Per~~Net ~~Share~~Income (~~Basic~~Loss): as(2,319) ~~reported~~398 .31 117 (~~$3.28~~31) (~~$0.41~~1,804) ~~Pro~~Total ~~Forma~~Assets .10,603 .9,944 .629 .25,098 .(21,914) .24,360 .----------------------------------------------------------------------------------------------- .2004 .---- .Revenues .$1,034 .- ~~($3.28)~~- (- - $~~0.40)~~1,034 ~~Loss~~Operating ~~Per~~Expenses ~~Share~~2,880 ~~(Diluted):~~- as- ~~reported~~451 (~~$3.28~~135) ~~($0.41)~~3,196 ~~Pro~~Segment ~~Forma~~Net .Loss .(1,844) .- .- .(254) .- .(2,098) .Total .Assets .4,740 .- .- ~~($3.28)~~11,266 (~~$0.40~~4,043) 11,963 -----------------------------------------------------------------------------------------------

(1) Includes HoustonStreet. BayCorp began consolidating HoustonStreet as of May 1, 2004. See "Note A. The Company." NOTE I - NEW ACCOUNTING PRONOUNCEMENTS FASB Statement No. 123 (Revised 2004), Share-Based Payment (SFAS 123R) was issued in December 2004. SFAS 123R replaces SFAS No. 123, Accounting for Stock-Based Compensation (SFAS 123), and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123R requires companies to recognize in the financial statements the compensation cost related to share-based payment transactions with employees. The compensation cost is measured based upon the fair value of the instrument issued. Share-based compensation transactions with employees covered within SFAS 123R include share options, restricted share plans, performance-based awards, share appreciation rights, and employee share purchase plans. SFAS 123R will be effective as of the first annual reporting period that begins after December 15, 2005. Since January 2003, the Company used the fair value based method recognition of compensation expense and is required to apply the modified prospective application transition method under SFAS 123R. The modified prospective application transition method requires the application of this standard to all new awards issued after the effective date, all modifications, repurchased or cancellations of existing awards after the effective date, and unvested awards at the effective date. For unvested awards, the compensation cost related to the remaining service period that has not been rendered at the effective date will be determined by the compensation cost calculated currently under SFAS 123. The Company will be adopting the modified prospective application of SFAS 123R. Based on the current options outstanding, the Company anticipates the adoption of this statement to not result in the recognition of any incremental compensation cost to be recognized in the year of adoption. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. ---------------------------------------------------------- Overview 15 BayCorp derived its revenues primarily through energy sales activities by Great Bay Power Marketing, Great Bay Hydro, Great Bay Hydro Maine and Nacogdoches Gas in the first quarter of 2005 and from Great Bay Power Marketing in the first quarter of 2004. Great Bay Power Marketing currently holds one purchased power contract with Unitil. On April 1, 2004, Great Bay Hydro completed an acquisition of generating facilities including an operating hydroelectric facility of approximately 4 megawatts located in Newport, Vermont, diesel engine generators totaling approximately 7 megawatts located in Newport, Vermont and non- operating hydroelectric facilities in Troy and West Charleston, Vermont. Great Bay Hydro assumed operating responsibility of the generating facilities on April 1, 2004. Great Bay Hydro uses the output of the Newport plant as a physical hedge for meeting a portion of the Company's contractual obligations under the Unitil PPA. On March 16, 2005, GBH Maine and GBH Benton acquired Benton Falls Associates, L.P., a limited partnership that owns a 4.3 megawatt hydroelectric generation plant in Benton, Maine ("Benton Falls"), from The Arcadia Companies for approximately $2.2 million. The Company assumed operating responsibility for Benton Falls, the output of which is sold to CMP under a power purchase agreement that expires in December 2007. The rates under the CMP PPA are indexed to CMP's standard rates for energy and capacity purchases established annually by the Maine Public Utilities Commission. In the fourth quarter of 2004, Nacogdoches Gas entered into agreements with Sonerra under which Nacogdoches Gas acquired an approximate 10% working interest in two natural gas and oil producing wells. Nacogdoches Gas entered into an agreement dated January 7, 2005 with Sonerra, under which Nacogdoches Gas will fund the development of three natural gas and oil wells. This agreement was amended as of March 14, 2005, increasing the number of wells from three to four. In addition, Nacogdoches Gas has an option to participate in Sonerra's continued development of up to 15 additional natural gas and oil wells over the next two years. Under the agreement with Sonerra, Nacogdoches Gas will fund the total cost of the new wells (with the provision that up to 25% of the working interest may be funded and acquired by other parties) and will receive a priority return of 90% of the working interest funded until its aggregate investment is recovered. Once Nacogdoches Gas has recovered all of its investment in the wells from the net proceeds of all wells and any other revenues from the assets acquired under the development agreement, Sonerra and Nacogdoches Gas will own equal amounts of the working interests funded. The working interests include undivided leasehold interests in the gas units and the production and gathering equipment. Since entering the January 7, 2005 agreement with Sonerra, Nacogdoches Gas has funded the development of four wells. The net revenue interest in each of these four wells being funded by Nacogdoches Gas is 77% with the remaining 23% of the net revenues paid to the lessor and other royalty interests. Nacogdoches Gas has a 90% ownership percentage in each of these wells and a 100% cost percentage. This means that Nacogdoches Gas has a working interest that bears 100% of the operating costs of the wells and receives 69.3% of the net revenues from the wells. The first of those wells, Round Mountain, a James Lime horizontal natural gas well, began production in January 2005 and through the end of March 2005 has produced approximately 134 million cubic feet of natural gas. The second well, Wicked Wolf, a James Lime horizontal natural gas well, began production in early March 2005 and through the end of March 2005 as produced approximately 73 million cubic feet of natural gas. The third and fourth wells, Painted Horse, a Rodessa vertical natural gas well , and Whirlwind, a James Lime horizontal natural gas well, are being developed. Expenses for the first quarter of 2004 and 2003 primarily consisted of the cost of purchased power, production, general and administrative costs and unrealized losses for the mark to market of the Company's energy contract. 16 As of May 1, 2004, BayCorp began consolidating HoustonStreet for financial reporting purposes and HoustonStreet revenues and expenses are reflected in the Company's financials as of that date. See "Note E. Investment in HoustonStreet." The following discussion focuses solely on operating revenues and operating expenses and is presented in a substantially consistent manner for all of the periods presented. Results of Operations: First Quarter of 2005 Compared to the First Quarter of 2004 ------------------------------------------------------------ Operating Revenues BayCorp's operating revenues increased by approximately $1,326,000 to $2,360,000 in the first quarter of 2005 as compared to $1,034,000 in the first quarter of 2004. Total revenues for the first quarter of 2005 included approximately $985,000 generated from Great Bay Power Marketing's long-term power sales contract with Unitil and approximately $25,000 in net revenues from Great Bay Power Marketing's energy commodity trading activity. The gross retail sales volume of energy commodity trading activity was approximately $513,000 and the related cost of sales was approximately $488,000. Great Bay Hydro generated revenues in the first quarter of 2005 of approximately $148,000 from the sale of electricity and Nacogdoches Gas generated revenues of approximately $931,000 from the sale of natural gas. HoustonStreet generated revenues of approximately $243,000. Consolidated operating revenues in 2004 were approximately $1,034,000 and were derived solely from Great Bay Power Marketing's long-term power sales contract with Unitil. The Company realized an average selling price for electricity sold under the Unitil sales contract of 5.03 cents per kilowatt hour ("kWh") for the first quarters of both 2005 and 2004. The cost of power purchased to supply this contract was approximately 6.12 cents per kWh for the first quarter of 2005 and approximately 5.78 cents per kWh for the first quarter of 2004. For the first quarter of 2005, the Company realized an average selling price for electricity generated and sold by Great Bay Hydro of approximately 6.18 cents per kWh and Great Bay Hydro's cost of generating power (determined by dividing total operating expenses by kWhs sold during the applicable period) was approximately 12.06 cents per kWh. Expenses Great Bay Power Marketing purchases power to satisfy its power supply obligation under the Unitil contract. Purchased power expenses increased by approximately $67,000, or 5.9%, to $1,198,000 in the first quarter of 2005 as compared to $1,131,000 in the first quarter of 2004. The Company recorded a non-cash charge for an unrealized loss on the mark-to-market of its long term energy sales contract and recorded the amortization of the deferred inception gain on this contract for a total net unrealized loss of approximately $1,989,000 in the first quarter of 2005 as compared to a net unrealized loss of approximately $1,637,000 in the first quarter of 2004. The mark-to-market value of this long-term contract is based on current projections of power prices over the life of the contract. Forward power prices increased during the first quarter of 2004 and have continued to rise into the first quarter of 2005 primarily due to increases in the forward price of natural gas. In the New England Power Pool ("NEPOOL"), power generating plants are usually dispatched in the order of increasing variable costs. The plants that are called upon to supply the last amount of demand are considered to be on the margin and set the price of power for all plants selling into the market. Since the completion of a significant amount of new gas- fired generation in NEPOOL, plants that use natural gas as a fuel source are frequently on the margin and therefore set the price of power in NEPOOL. 17 Accordingly, the price of power in NEPOOL is highly influenced by the price of natural gas. Production and transmission expenses were approximately $211,000 in the first quarter of 2005 and reflect plant operating expenses Great Bay Hydro and at Benton Falls. There were no production and transmission expenses in the first quarter of 2004. Administrative and general expenses increased approximately $312,000, or 75.2%, to $727,000 in the first quarter of 2005 as compared to $415,000 in the first quarter of 2004. This increase is primarily attributable to administrative and general expenses associated with the Company's operations at Great Bay Hydro, Great Bay Hydro Maine, Nacogdoches Gas, Nacogdoches Power and at HoustonStreet. There were no expenses associated with these operations in the first quarter of 2004. Depreciation, depletion and amortization was approximately $270,000 in the first quarter of 2005 and represents depletion of Nacogdoches lease acquisition costs and development costs for the first quarter of 2005. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. The provision for depletion is based upon the units of production method. There were no similar expenses in the first quarter of 2004. Taxes other than income increased approximately $47,000, to $60,000 in the first quarter of 2005 as compared to $13,000 in the first quarter of 2004 primarily due to Great Bay Hydro property taxes. There was no property tax expense in the first quarter of 2004. Total other income increased approximately $247,000, to $311,000 in the first quarter of 2005 as compared to $64,000 in the first quarter of 2004. This increase was primarily attributable to a refund of $225,000 from the State of New Hampshire for overpayment of prior year state income taxes. Net Loss As a result of the above factors, for the first quarter of 2005, the Company recorded a net loss of approximately $1,804,000, or $3.23 per share, as compared to a net loss of approximately $2,098,000, or $3.33 per share, for the first quarter of 2004. Liquidity and Capital Resources As of March 31, 2005, BayCorp had approximately $8,093,000 in cash and cash equivalents. The Company had approximately $2,500,000 in restricted cash as required by the terms of the Unitil PPA and approximately $436,000 in restricted cash as required by the terms of the CMP PPA The restricted cash is reflected as a long term asset in the Company's financial statement. The Company also had approximately $520,000 in a cash deposit at ISO New England ("ISO NE"). The Company purchases a portion of its power needed for resale from ISO NE and ISO NE requires financial assurance to protect NEPOOL against a payment default of one of its participants. The amount of collateral needed is calculated based upon formulas developed by ISO NE and NEPOOL. This deposit is reflected as an Other Long Term Asset in the Company's financial statements. The Company believes that such cash, together with the anticipated proceeds from the sale of electricity by Great Bay Power Marketing, Great Bay Hydro and Benton Falls, and from the sale of natural gas and oil by Nacogdoches Gas, will be sufficient to enable the Company and its wholly owned subsidiaries to meet their cash requirements for operations in 2005. 18 On March 15, 2005, the Company and all of its wholly owned subsidiaries entered into a $10,250,000 Convertible Note and a Pledge Agreement with Sloan Group Ltd., a Bahamas corporation. The debt, which accrues interest at 8% per annum and is due and payable in full on December 15, 2005, is convertible by the Sloan Group at any time between November 15, 2005 and December 15, 2005 (or any time after the occurrence and during the continuance of a material event of default under the Note) into shares of BayCorp's common stock, $.01 par value at a price of $14.04 per share. The Note does not allow BayCorp to prepay the debt and provides for a 2% premium on the interest rate in the event of a default. Payment of the Note may be accelerated in the event of a material event of default, which is customary for this type of financing. See "Note B. Debt Financing." If payment on the Note is required on December 15, 2005, the Company may seek additional financing. The Company had a net loss in the first quarter of 2005 of approximately $1,804,000. There was a non-cash charge for an unrealized loss on the mark-to-market of the Unitil PPA of approximately $2,054,000 and a non-cash recognition of deferred gain on the Unitil PPA of approximately $65,000. The value of this contract is based on current projections of power prices over the life of the contract. Forward power prices increased during the first quarter of 2005 primarily due to increases in the forward price of natural gas. Power generating plants that use natural gas as a fuel source are increasingly on the margin and therefore are setting the forward price of power in NEPOOL. Accordingly, the price of power in NEPOOL is highly dependent on the price of natural gas. Other non-cash charges included compensation expense of approximately $43,000 for the variable accounting of certain employee stock options, $36,000 in interest expense on the convertible note, approximately $20,000 for minority interest and approximately $270,000 for depreciation, depletion and amortization. An increase in accounts receivable in the first quarter of 2005 of approximately $642,000 was primarily attributable to accounts receivable at Nacogdoches Gas. An increase of approximately $404,000 in prepaids and other assets was primarily attributable to $436,000 that has been escrowed as required by the terms of the CMP PPA with Benton Falls. A decrease in accounts payable and accrued expenses of approximately $66,000 was primarily attributable to a reduction in accounts payable as of March 31, 2005. Cash flows from investing activities included cash expenditures of approximately $2,129,000 for fixed assets as part of the Benton Falls purchase. See "Note A. The Company." Investing activities in the first quarter of 2005 also included investments by Nacogdoches Gas of approximately $8.9 million for interests in four oil and natural gas wells. See "Note A. The Company." The Company's contractual obligations as of March 31, 2005 were as follows: More Contractual Less Than 1-3 3-5 Than 5 Obligations Total One Year Years Years Years ----------- ----- -------- ----- ----- ----- Office Space $26,400 $26,400 0 0 0 Lease Following the sale of Seabrook in the fourth quarter of 2002 and the completion of the Company's Tender Offer in the first quarter of 2003, the Company evaluated and pursued energy-related investment opportunities. The Company continues to focus on the acquisition of energy-related assets. BayCorp has continued to seek to acquire either complete or partial ownership interests in electric generating facilities. This is an area where BayCorp has a solid understanding of the market and the value of and risks related to those assets. There are also a large number of generating assets that have been offered or are currently being offered for sale. These plants 19 consist of both merchant and contracted facilities using a variety of fuels and located both domestically and internationally. There is, however, substantial competition for the acquisition of these assets, with a number of new participants entering the market, including private equity funds, hedge funds, insurance companies, Canadian income funds and investment banks. The Company remains focused on pursuing opportunities and assets that it believes will provide a return to stockholders commensurate with the risks. Generally, BayCorp has targeted the following operating assets: (1) merchant plants in regions with developed wholesale power markets such as New England, New York, PJM and Texas, (2) international assets that have stable, long-term off-take contracts, and (3) merchant or contracted renewable assets. BayCorp is also pursuing other energy-related investments including development of new power generation facilities and hydrocarbon (natural gas and oil) reserves and the further development of HoustonStreet, its online trading platform. BayCorp's first acquisition following its sale of Seabrook was the acquisition through Great Bay Hydro of the Vermont generating plants owned by the Vermont Electric Division of Citizens. The generating facilities include an operating hydroelectric facility of approximately 4 MWs located in Newport, Vermont, diesel engine generators totaling approximately 7 MWs located in Newport, Vermont and non-operating hydroelectric facilities in Troy and West Charleston, Vermont. Great Bay Hydro assumed operating responsibility for these facilities on April 1, 2004 and is using the output of the Newport plant as a physical hedge for a portion of BayCorp's contractual obligation to supply 9.06 megawatts to Unitil through 2010. Great Bay Hydro paid a nominal purchase price to Citizens for the generating facilities and 650 acres of real property associated with the generating facilities, and this amount is reflected in the Company's financial statements. In addition, Citizens agreed to indemnify Great Bay Hydro for the reasonably anticipated costs of complying with the requirements of the new operating license issued by the FERC on November 21, 2003. On September 28, 2004, Great Bay Hydro agreed to terminate Citizens' indemnification requirements in exchange for Citizens' payment to Great Bay Hydro of approximately $4.4 million for FERC compliance. The Company's balance sheet as of March 31, 2005 reflects short-term and long-term liabilities of $532,000 and $2,479,000, respectively, for the estimated remaining cost of FERC compliance. The Company expects to complete the requirements of FERC license within those amounts. The Company formed Nacogdoches Power in 2004, and through this subsidiary, acquired the development rights to the Sterne Power project in the town of Sacul in Nacogdoches County, Texas. The Sterne project was initially designed and has been permitted as a nominal 1000 MW plant. The project received its air quality permit in December 2002, and the air quality permit currently is effective through December 7, 2005. An additional eighteen-month extension to the permit may be requested by Nacogdoches Power. The wastewater discharge permit is currently effective through August 1, 2006. The project has an option to purchase the land for the project and options to acquire easements for transmission lines and/or gas pipelines. Those options have varying expiration dates in 2005 and 2006 and are either being extended or exercised. Nacogdoches Power is currently evaluating the plant configuration. Further, Nacogdoches Power is seeking to enter into power offtake contracts, although 20 none have been executed. A schedule for the development of the project has not been established. The total cost of the Sterne project will depend on the final plant design and will require substantial additional financing. The amount and type of any such financing has not been determined. As part of its efforts to secure a natural gas supply for the Sterne Power project, the Company determined that significant natural gas and oil exploration and production activities were being carried out in Nacogdoches County, Texas near the location of the Sterne Power project. It was through this process that the Company identified the oil and gas development opportunity with Sonerra. The Company formed Nacogdoches Gas in 2004, and in the fourth quarter of 2004, Nacogdoches Gas entered into agreements with Sonerra under which Nacogdoches Gas acquired an approximate 10% working interest (of a 77% net revenue interest) in two natural gas and oil producing wells. Nacogdoches Gas entered into an agreement dated January 7, 2005 with Sonerra, under which Nacogdoches Gas will fund the development of three natural gas and oil wells. This agreement was amended as of March 14, 2005, increasing the number of wells from three to four. Since entering the January 7, 2005 agreement with Sonerra, Nacogdoches Gas has funded the development of four wells. The net revenue interest in each of these four wells being funded by Nacogdoches Gas is 77% with the remaining 23% of the net revenues paid to the lessor and other royalty interests. Nacogdoches Gas has a 90% ownership percentage in each of these wells and a 100% cost percentage. This means that Nacogdoches Gas has a working interest that bears 100% of the operating costs of the wells and receives 69.3% of the net revenues from the wells. The first of those wells, Round Mountain, a James Lime horizontal natural gas well, began production in January 2005 and through the end of March 2005 has produced 134 million cubic feet of natural gas. The second well, Wicked Wolf, a James Lime horizontal natural gas well, began production in early March 2005 and through the end of March 2005 has produced approximately 73 million cubic feet of natural gas. The third and fourth wells, Painted Horse, a Rodessa vertical natural gas well, and Whirlwind, a James Lime horizontal natural gas well, are being developed. In addition, Nacogdoches Gas has an option to participate in Sonerra's continued development of up to 15 additional natural gas and oil wells over the next two years. Under the agreement with Sonerra, Nacogdoches Gas will fund the total cost of the new wells (with the provision that up to 25% of the working interest may be funded and acquired by other parties) and will receive a priority return of 90% of the working interest funded until its aggregate investment is recovered. Once Nacogdoches Gas has recovered all of its investment in the wells from the net proceeds of all wells and any other revenues from the assets acquired under the development agreement, Sonerra and Nacogdoches Gas will own equal amounts of the working interests funded. The working interests include undivided leasehold interests in the gas units and the production and gathering equipment. Sonerra directly or indirectly controls approximately 36,000 acres either through leases or as land held by production within a project area in Nacogdoches County in east Texas. Sonerra also has acquired 3D seismic data covering approximately 31,000 acres within the project area, of which 24,000 acres are under lease or held by production directly or indirectly by Sonerra. Under the terms of the January 7, 2005 agreement as amended, Sonerra will sequentially present five additional sets of three well prospects to Nacogdoches Gas. Upon the presentation of a set of three well prospects, Nacogdoches Gas, at its option, may proceed with the development of those three well prospects. Should Nacogdoches Gas decide not to proceed with the development of any given set of three well prospects, its right to participate in future well sets terminates. The total cost of an individual well typically ranges from $2.0 million to $3.5 million and includes the acquisition of leases for the land, the drilling and completion of the wells and the construction of extensions of the gas gathering system. The total cost depends on the type of well, the amount of land required for the production unit, the length of gas gathering pipeline and the completion technique. If Nacogdoches Gas exercises its option to participate in additional well prospects, it will need to raise additional capital to do so. 21 Other exploration and production companies are operating in Nacogdoches County and may seek to acquire land in or near the project area being developed by Sonerra and Nacogdoches Gas. Nacogdoches Gas has no employees. Various federal, state and local laws relating to the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact the development of oil and gas wells and their costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into the waters of the United States, underground injection of waste water, the generation, storage, transportation and disposal of waste materials and the protection of public health, natural resources and wildlife. The anticipated costs of development of oil and natural gas wells by Nacogdoches Gas and Sonerra includes funding for the measures necessary to meet environmental compliance requirements and no additional environmental compliance costs are anticipated. In April 2005, Nacogdoches Gas funded the acquisition of certain natural gas production assets in Nacogdoches County, Texas formerly owned by SunStone Corporation ("SunStone") for approximately $3.4 million. The assets include: Net Overriding Working Revenue Royalty Well Name Interest Interest Interest --------- -------- -------- -------- Kendrick #1-H 25.1 % 19.3 % 1.7 % Sitting Bull #1 25.1 % 19.3 % 1.3 % Crazy Horse #1 0.0 % 0.0 % 1.5 % Soaring Eagle #1 29.2 % 22.4 % 1.1 % Ten Bears #1 37.8 % 29.1 % 0.4 % Ten Bears #2 0.0 % 0.0 % 0.9 % Sky Chief #1 25.1 %* 19.3 %* 2.4 % *This is a back in interest that will be acquired after the recovery of a 300% non-consent penalty. - A 75.6% ownership interest in 3D seismic survey data that covers approximately 49 square miles in Nacogdoches County. - A 37.8% undivided leasehold interest in approximately 3,800 acres within the area covered by the 3D seismic survey data. - Undivided interests in the Melrose Gas Gathering Pipeline System (the "Melrose System"), located within the Kendrick (James Lime) Field, Nacogdoches County, Texas, consisting of: (i) an undivided 25% interest in the section of the Melrose System originating at mile-post 207.68 marker as a 6" tap in the Texas Eastern line, and extending West through a 6" pipeline to the Sonerra, Kendrick No. 1-H well, (ii) an undivided 29.1552% interest in the section of the Melrose System occurring from the Kendrick No.1 well and extending as a 6" pipeline to the Sonerra, Soaring Eagle No.1 well and (iii) an undivided interest in all rights of way, equipment and appurtenances relating to such segments, and including all facilities and equipment presently existing at and associated with the Texas Eastern tap site and facility. Nacogdoches Gas acquired these assets in accordance with the terms of the January 7, 2005 agreement with Sonerra and the Acquisition Agreement dated as of March 22, 2005 among Sonerra, Pinnacle Energy Group, L.C. and Nacogdoches Gas. Under its agreement with Sonerra, Nacogdoches Gas will have a 90% interest and Sonerra will have a 10% interest in these assets until 110% of the $3.4 million purchase price of the SunStone assets and all of the funding provided by Nacogdoches Gas for wells drilled under the January 7, 2005 agreement is recovered. Once Nacogdoches Gas recovers its investment and 22 other operating costs, its interest in all assets will become 50% and Sonerra will own the other 50%. In March 2005, BayCorp formed GBH Maine and GBH Benton. On March 16, 2005, GBH Maine and GBH Benton acquired Benton Falls Associates, a limited partnership that owns a 4.3 megawatt hydroelectric generation plant in Benton, Maine from The Arcadia Companies for approximately $2.2 million. The Company assumed operating responsibility for Benton Falls, the output of which is sold to CMP under a power purchase agreement that expires in December 2007. The rates under the CMP PPA are indexed to CMP's standard rates for energy and capacity purchases established annually by the Maine Public Utilities Commission. The Company intends to pursue investments that will require additional equity or debt financing. The Company believes that such financing is available, but there can be no assurance that the Company would be successful in obtaining such financing. If the Company is not successful in obtaining additional financing, the Company may not be able to pursue certain investment alternatives. In such a case, the Company may be limited to opportunities that it can pursue given its current resources. The Company believes that its current cash, together with the anticipated proceeds from the sale of electricity by Great Bay Power Marketing, Great Bay Hydro and Benton Falls, and the proceeds from the sale of natural gas by Nacogdoches Gas, will be sufficient to enable the Company to meet the anticipated cash requirements of its current operations in 2005. If the Company is unsuccessful in identifying and making additional investments, the Company may pursue alternative strategies, including sale of the Company or its assets, or deregistration. Critical Accounting Policies Preparation of the Company's financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities and revenues and expenses. Note 1 to the Consolidated Financial Statements in the Company's Form 10-K, filed March 31 2005, is a summary of the significant accounting policies used in the preparation of the Company's financial statements. The following is a discussion of the most critical accounting policies used historically by the Company. Stock Options The Company accounts for its stock option plans in accordance with SFAS No. 123, "Accounting for Stock Based Compensation." Awards under the Company's plans vest over periods ranging from one to three years. Principles of Consolidation The Company consolidates all majority-owned and controlled subsidiaries and applies the equity method of accounting for investments between 20% and 50%. All significant intercompany transactions have been eliminated. All sales of subsidiary stock are accounted for as capital transactions in the consolidated financial statements. The Company began consolidating its subsidiary, HoustonStreet, as a result of the recapitalization that occurred on April 30, 2004. As a result of the recapitalization, the Company's ownership in HoustonStreet increased from 46.4% to 59.7%. Energy Marketing 23 Forward contracts (including the Unitil PPA) meeting the definition of a derivative and not designated and qualifying for the normal purchases and normal sales exception under Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133) are recorded at fair value. In accordance with FASB's Emerging Issues Task Force Issue No. 02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities (EITF Issue No. 02-03), revenues related to derivative instruments classified as trading are reported net of related cost of sales. Depletion of Oil and Gas Properties The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such impairment is charged to expense in that period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and geological and geophysical expenses, are expensed as incurred. The provision for depletion is based upon the units of production method. Asset Retirement Obligation The Company has adopted the provisions of Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long- lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The Company has asset retirement obligations associated with the future plugging and abandonment of proved properties and related facilities. The estimated liability is based upon historical experience in plugging and abandoning wells, estimated remaining lives of those wells, estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk- free interest rate or remaining lives of the wells, or if federal of state regulators enact new plugging and abandonment requirements. Forward Looking Statements and Certain Factors That May Affect Future Results -------------------------------------------------------------- This Quarterly Report contains forward-looking statements. For this purpose, any statements contained in this report that are not statements of historical fact may be deemed to be forward-looking statements. Without limiting the foregoing, the words "believes," "anticipates," "plans," "expects," "intends" and similar expressions are intended to identify forward-looking statements. There are a number of important factors that could cause the results of BayCorp and/or its subsidiaries to differ materially from those indicated by such forward-looking statements. These factors include, without limitation, those set forth below and elsewhere in this report. Business Opportunities and Development. As described in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources," the Company has evaluated and pursued energy-related investment opportunities, has focused on the acquisition of 24 natural gas and oil, electric generating assets and other energy- related investments and is considering the further development of HoustonStreet. There can be no assurance that the Company will be able to identify business opportunities that it believes to be attractive, or that it will be successful in pursuing any such opportunities, in view of factors that include competition for the acquisition of assets, the fact that many energy-related activities are subject to government regulatory requirements, the Company's limited resources and the need to obtain debt or equity financing in order to pursue certain opportunities. History of Losses. BayCorp reported operating losses in 2004 and in 2003 and reported operating income for 2002 and 2001. Prior to 2001, BayCorp had never reported an operating profit for any year since its incorporation. Liquidity Need. As of March 31, 2005, BayCorp had approximately $11.0 million in cash and cash equivalents, restricted cash and short-term investments. On March 15, 2005, BayCorp closed a $10.25 million convertible debt financing with Sloan Group Ltd. The debt, which accrues interest at 8% and is due on December 15, 2005, is convertible at any time between November 15, 2005 and December 15, 2005 into shares of the Company's common stock at a price of $14.04 per share. BayCorp used proceeds from the financing to finance the acquisition of Benton Falls by GBH Maine and GBH Benton and intends to use proceeds from the financing to continue the development of natural gas and oil wells in East Texas under its Project Development Agreement with Sonerra and for other strategic and general corporate purposes. The Company believes that such cash, together with the anticipated proceeds from the sale of electricity by Great Bay Power Marketing, Great Bay Hydro and Benton Falls, and from the sale of natural gas and oil by Nacogdoches Gas, will be sufficient to enable the Company and its wholly owned subsidiaries to meet their cash requirements for operations in 2005. The direction of the Company's business and circumstances, foreseen or unforeseen, may cause cash requirements to be materially higher than anticipated and the Company or its wholly-owned subsidiaries may be required to raise additional capital, either through a debt financing or an equity financing, to meet ongoing cash requirements. There is no assurance that the Company or its subsidiaries would be able to raise such capital or that the terms on which any additional capital is available would be acceptable. Moreover, the Company's need to raise additional capital in order to pursue certain opportunities may affect the Company's competitive position with respect to such opportunities. If additional funds are raised by issuing equity securities, dilution to then existing stockholders will result. Purchased Power Price Risk. The price of electricity is subject to fluctuations resulting from changes in supply and demand. The Company is party to a purchased power contract with Unitil that provides for Great Bay Power Marketing to sell to Unitil 9.06 MWs at $50.34 per MWh. The Unitil PPA continues through October 31, 2010, and Unitil has an option, expiring November 1, 2005, to extend the Unitil PPA for up to 12 years until 2022. The Company must purchase power to meet its obligation under the PPA. The prices at which Great Bay Power Marketing must purchase its power supply could increase significantly from current levels. Extensive Government Regulation of Electric Energy Industry. The electric energy industry is subject to extensive regulation by federal and state agencies. Great Bay Power Marketing, Great Bay Hydro and Benton Falls are subject to the jurisdiction of the FERC and, as a result, are required to file with FERC all contracts for the sale of electricity. FERC's jurisdiction also includes, among other things, the sale, lease, merger, consolidation or other disposition of facilities, interconnection of certain facilities, accounts, service and property records. The Sterne Power project is subject to the terms of its environmental permits. The Sterne Power project currently has an air quality permit and wastewater discharge permit issued by the Texas Commission on Environmental Quality. Additional environmental permits will 25 be required prior to the start of operation of the project. In addition, prior to operation of the Sterne Power project, Nacogdoches Power will seek designation by FERC as an EWG. Extensive Government Regulation of Oil and Gas Industry. There are numerous federal and state laws and regulations governing the oil and gas industry that are often changed in response to the current political or economic environment. Compliance with this regulatory burden is often difficult and costly and may carry substantial penalties for noncompliance. The following are some specific regulations that may affect oil and gas activities. The impact of these or future legislative or regulatory initiatives cannot be predicted. Federal Energy Bill. After failing to pass legislation in 2003 and 2004, Congress is currently considering a new energy bill. The potential effect of this legislation is unknown, but it may include certain tax incentives for oil and gas producers and changes in the federal regulatory framework. Federal Regulation of Natural Gas. The interstate transportation and certain sales for resale of natural gas, including transportation rates charged and various other matters, is subject to federal regulation by FERC. Federal wellhead price controls on all domestic gas were terminated on January 1, 1993, so gathering systems are currently not subject to FERC regulation. The impact of future government regulation on any natural gas facilities cannot be predicted. Although FERC's regulations should generally facilitate the transportation of gas produced from producing properties and the direct access to end- user markets, the future impact of these regulations on marketing production or on gas transportation business cannot be predicted. BayCorp and its subsidiaries, however, should not be affected differently than competing producers and marketers. Federal Regulation of Oil. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The net price received from the sale of these products is affected by market transportation costs. Under rules adopted by FERC effective January 1995, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. State Regulation. Oil and gas operations are subject to various types of regulation at the state and local levels. Such regulation includes requirements for drilling permits, the method of developing new fields, the spacing and operations of wells, and waste prevention. The production rate may be regulated and the maximum daily production allowable from oil and gas wells may be established on a market demand or conservation basis. These regulations may limit production by well and the number of wells that can be drilled. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the state's administrative authority charged with regulating pipelines. The rates that can be charged for gas, the transportation of gas, and the construction and operation of such pipelines would be subject to the regulations governing such matters. Certain states have recently adopted regulations with respect to gathering systems, and other states are considering similar regulations. Whether new regulations will be adopted or, if adopted, the effect these rules may have on gathering systems cannot be predicted. Federal, State or Native American Leases. Operations on federal, state or Native American oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. Such operations must be conducted pursuant to certain on-site security regulations and other permits and authorizations issued by the Bureau of Land Management, Minerals Management Service and other agencies. 26 Environmental Regulations. Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and gas exploration, development and production operations, and consequently may impact operations and costs. These laws and regulations govern, among other things, emissions to the atmosphere, discharges of pollutants into waters of the United States, underground injection of waste water, the generation, storage, transportation and disposal of waste materials, and protection of public health, natural resources, and wildlife. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from operations and may require the suspension or cessation of operations in affected areas. To date, BayCorp has not expended any material amounts to comply with such regulations, and management does not currently anticipate that future compliance will have a materially adverse effect on BayCorp's consolidated financial position or results of operations. BayCorp is committed to environmental protection and believes that it is in substantial compliance with applicable environmental laws and regulations. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of its facilities or operations. BayCorp expects that it will make expenditures in efforts to comply with environmental regulations and requirements. These costs are considered a normal, recurring cost of ongoing operations and not an extraordinary cost of compliance with government regulations. Risks Related to HoustonStreet. HoustonStreet's revenues depend on continued and expanded use of Internet-based wholesale energy trading platforms. Electronic trading of wholesale energy may not achieve widespread market acceptance or emerge as a sustainable business. In addition, HoustonStreet will need to enhance trading liquidity in order to increase and sustain revenues. As a technology dependent business, HoustonStreet's business could suffer due to computer or communications systems interruptions or failures, technological change or adverse competitive developments. Further, as electronic commerce evolves, federal, state and foreign agencies could adopt regulations covering issues such as user privacy, content and taxation of products and services. If enacted, government regulations could materially adversely affect HoustonStreet's business. Although HoustonStreet currently is not aware that it infringes any other patents, it is possible that HoustonStreet's technology infringes patents held by third parties. If HoustonStreet were to be found infringing, the owner of the patent could sue HoustonStreet for damages, prevent HoustonStreet from making, selling or using the owner's patented technology or could impose substantial royalty fees for those privileges. If any of the foregoing risks materialize, or other risks develop that adversely affect HoustonStreet, or if HoustonStreet fails to grow its revenues and net income, BayCorp could lose all of the value of its investment in HoustonStreet. Item 3. Quantitative and Qualitative Disclosures About Market Risk -------------------------------------------------------------- Commodity Price Risk Great Bay Power Marketing is a party to the Unitil PPA, which as amended, provides for the sale of 9.06 MWs of power to Unitil at $50.34 MWh through October 31, 2010. Unitil has an option, which expires November 1, 2005, to extend the Unitil PPA for up to 12 years, from November 1, 2010 through October 30, 2022. Great Bay Power Marketing purchases power to meet its obligation under this contract and, as such, is exposed to market price fluctuations for the price of power. The Unitil PPA was entered into for purposes other than trading and is subject to commodity price risk. The prices of electricity are subject to fluctuations resulting from changes in supply and demand. Great Bay Power Marketing tracks market exposure on its forward firm energy contract in a mark-to-market model that is updated daily with current market prices and is reflected in the Company's balance sheet. The positive, or negative, value of the forward firm power commitment represents an estimation of the gain, or loss, that Great Bay Power Marketing would have experienced if open firm commitments were covered at then-current market prices. Great Bay Power Marketing had net unrealized losses in the first quarters of 2005 and 2004 of approximately $1,989,000 and $1,637,000, respectively, on its forward firm energy contract. 27 The Company does not purchase derivative commodity instruments to hedge its exposure to commodity price risk. The generation and sale of electricity by Great Bay Hydro of approximately 4 megawatts functions as a physical hedge against the commodity risk. The following table provides information about the Company's forward firm energy contract that is subject to changes in commodity prices, showing the fair value of the contract as of March 31, 2005 and 2004 and the unrealized loss for those periods. March 31, March 31, 2005 2004 --------- --------- (Dollars in thousands) Fair Value (3/31) ($5,479) ($1,699) Unrealized Gain (Loss) ($2,054) ($1,703) Item 4. Controls and Procedures ------------------------------- Evaluation of Disclosure Controls and Procedures The Chairman, CEO, and President and the Vice President of Finance of the Company have reviewed and evaluated the effectiveness of disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 (the "Exchange Act") Rules 240.13a and 15(e)) as of the end of the fiscal quarter covered by this Quarterly Report. Based on that evaluation, the Chairman, CEO, and President and the Vice President of Finance have concluded that their current disclosure controls and procedures are, in all material respects, effective and timely, providing them with material information relating to that required to be disclosed in the reports the Company files or submits under the Exchange Act. The Company's management, including the Chairman, CEO and President and the Vice President of Finance, does not expect that the Company's disclosure controls and procedures or its internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, provides reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system reflects resource constraints; the benefits of controls must be considered relative to their costs. Because there are inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been or will be detected. These inherent limitations include the realities that judgments in decision- making can be faulty and that breakdowns occur because of simple error or mistake. Controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events. There can be no assurance that any design will succeed in achieving its stated goals under all future conditions; over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the policies or procedures. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Changes in Internal Controls There have not been any significant changes in the Company's internal controls or, to its knowledge, in other factors that have materially affected, or are reasonably likely to materially affect, these controls subsequent to the date of their evaluation. The Company is not aware of any significant deficiencies or material weaknesses and, therefore, no corrective actions were taken. 28 Part II - OTHER INFORMATION Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds ----------------------------------------------------------- Share Repurchase Plan. The following table summarizes repurchases of BayCorp stock during the fiscal quarter ended March 31, 2005:

AsMaximum ofNumber ~~and for the six months GBPM ended June 30 ($000's) and Houston Elimina- GBH Street Other tions~~ Total ~~---------------------------~~Number ~~------~~of ~~------~~Shares ~~------~~of ~~------~~Shares ~~------~~that ~~2004~~May ~~----~~Purchased ~~Revenues~~as ~~$2,321~~Part ~~$156~~of $0Yet $0Be ~~$2,477~~Purchased ~~Operating~~Publicly ~~Expenses~~Announced ~~4,823~~Plans ~~162~~Under ~~819~~the ~~(270)~~Plans ~~5,534~~or ~~Interest~~Period ~~Expense~~Shares 0Average 0Price 0or 0Programs 0Programs ~~Segment Net Income~~ (~~Loss~~1) ~~(2,489) (3) 487 3 2,002 Total Assets 5,871 515 19,431 (14,166) 11,651 Capital Expenditures 0 0 0 0 0~~ ------ Repurchased Per Share ------------------------ ----------------~~------------------------------------------~~ ~~2003~~Quarter ~~---- Revenues $~~1~~,987~~ 0- 02005 0 ~~$1,987~~-- ~~Operating~~-- ~~Expenses 2~~100,~~915 0 1,830 (270) 4,475 Interest Expense 0 0 0 0 0 Segment Loss (911) 0 (816) 0 (1,727) Total Assets 6,136 0 24,409 (15,193) 15,352 Capital Expenditures 0 0 0 0 0~~024

(1) On September 29, 2003, the Company announced that its Board of Directors had authorized the repurchase of up to ten percent of its fully diluted common stock on the open market or in negotiated transactions. On September 15, 2004 the Company announced that its Board of Directors had authorized the repurchase of up to an additional 100,000 shares of its common stock on the open market or in negotiated transactions. The Board of Directors did not establish expiration dates for either of these plans. Item 6. Exhibits ----------------- (a) See Exhibit Index. 29 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BayCorp Holdings, Ltd. May 16, 2005 /s/ Frank W. Getman Jr. ------------------------------------- Frank W. Getman Jr. President and Chief Executive Officer and Principal Financial Officer 30 EXHIBIT INDEX . Exhibit No Description ---------- ----------- 31.1 Certification of President and Chief Executive Officer (principal executive officer) pursuant to Exchange Act Rules 13a-14 and 15d-14. 31.2 Certification of President and Chief Executive Officer (principal financial officer) pursuant to Exchange Act Rules 13a-14 and 15d-14. 31.3 Certification of Vice President of Finance and Treasurer (chief accounting officer) pursuant to Exchange Act Rules 13a-14 and 15d-14. 32.1 Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Vice President of Finance and Treasurer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002. 99 BayCorp Holdings, Ltd. Earnings Release for the quarter ended March 31, 2005. 31

Contractual Total Less Than 1-3 Years 3-5 Years More Than Obligations One Year 5 Years ----------- ----- -------- --------- --------- -------- Office Space Lease $8,800 $8,800 0 0 0

Maximum Number of Shares that May Yet Shares Average Price Be Purchased Under Period Repurchased(1) Per Share the Plan ------ -------------- ------------- --------------------- February 2004 30,240 $13.05 May 2004 32,101 $13.19 June 2004 19,500 $13.10 24

Name For Withheld ---- ---- -------- Anthony M. Callendrello 580,064 21,973 Alexander Ellis 580,064 21,973 Stanley I. Garnett 580,064 21,973 Frank W. Getman Jr. 580,064 21,973 James S. Gordon 580,064 21,973 Thomas C. Leonard 580,064 21,973

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