BAYCORP HOLDINGS LTD - 10-Q Quarterly Report

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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

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PART I - FINANCIAL INFORMATION

Item 1. Financial Statements
- ----------------------------

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

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

4

(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

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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:

- 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.

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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.

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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

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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.

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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.

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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

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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

(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:

(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