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   June 30, 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
   Portsmouth, New Hampshire                  03801
  --------------------------              --------------
     (Address of principal                  (Zip Code)
      executive 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 July 15, 2005
------------------------------    -----------------------------
 Common Stock, $0.01 Par Value               571,364
           per Share


<Page>

                               INDEX

PART I - FINANCIAL INFORMATION:

Item 1 - Financial Statements:

Consolidated Statements of Operations -
   Three and Six Months Ended                                  3
   June 30, 2005 and 2004  . . . . . . . . . . . . . . .

Consolidated Balance Sheets at June 30, 2005
    and December 31, 2004  . . . . . . . . . . . . . . .       4

Consolidated Statements of Cash Flows -
    Six Months Ended June 30, 2005 and 2004  . . . . . .       5

Notes to Financial Statements  . . . . . . . . . . . . .       6

Item 2 - Management's Discussion and Analysis of
     Financial Condition and Results of Operations . . .      15

Item 3 - Quantitative and Qualitative
    Disclosures About Market Risk  . . . . . . . . . . .      28

Item 4 - Controls and Procedures . . . . . . . . . . . .      28

PART II - OTHER INFORMATION:

Item 2 - Unregistered Sales of Equity Securities
    and Use of Proceeds  . . . . . . . . . . . . . . . .      29

Item 4 - Submission of Matters to a Vote of
    Security Holders . . . . . . . . . . . . . . . . . .      29

Item 6 - Exhibits  . . . . . . . . . . . . . . . . . . .      30

Signatures . . . . . . . . . . . . . . . . . . . . . . .      31

Exhibit Index  . . . . . . . . . . . . . . . . . . . . .      32

                                 2


<Page>

PART I - FINANCIAL INFORMATION

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

<Table>
<Caption>

                      CONSOLIDATED STATEMENTS OF OPERATIONS
                                   (UNAUDITED)
                  (Dollars in thousands except per share data)

                                                  Three Months             Six Months
                                                 Ended June 30,          Ended June 30,
                                                 ---------------         --------------
                                                2005        2004        2005        2004
                                                ----        ----        ----        ----
<S>                                            <C>         <C>         <C>          <C>
Operating Revenues                              $3,474      $1,443      $5,834       $2,477

Operating Expenses
  Purchased Power                                1,153         998       2,351        2,129
  Unrealized Loss on Energy Contracts            1,399         716       3,388        2,353
  Production and Transmission                    2,317          22       2,528           22
  Administrative & General                         805         586       1,532        1,000
  Depreciation, Depletion and Amortization         429           0         699            0
  Taxes Other Than Income                           61          17         121           30
                                               -------     -------     -------      -------
      Total Operating Expenses                   6,164       2,339      10,619        5,534

Operating Loss                                  (2,690)       (896)     (4,785)      (3,057)

Other Income (Deductions)
  Interest and Dividend Income                      29          44          71           99
  Other Income (Deductions)                       (123)        667         (79)         676
                                               -------     -------     -------      -------
      Total Other Income (Deductions)              (94)        711          (8)         775
                                               -------     -------     -------      -------
Loss Before Income Taxes, Minority Interest
  And   Extraordinary Item                      (2,784)       (185)     (4,793)      (2,282)
Income Taxes                                         0           0         225            0
Minority Interest                                  (25)          2         (45)           2
                                               -------     -------     -------      -------
Loss Before Extraordinary Item                  (2,809)       (183)     (4,613)      (2,280)
Extraordinary Item                                   -         278           -          278
                                               -------     -------     -------      -------
Net Income (Loss)                              ($2,809)        $95     ($4,613)     ($2,002)
                                               =======     =======     =======      =======

Weighted Average Shares Outstanding -
  Basic and Diluted                            564,581     592,833     561,281      611,093
Loss Per Share before Extraordinary Item -
  Basic and Diluted                             ($4.98)     ($0.31)     ($8.22)      ($3.73)
Extraordinary Item Income Per Share -
  Basic and Diluted                                  -       $0.47           -        $0.45
Net Income (Loss) Per Share -
  Basic and Diluted                             ($4.98)      $0.16      ($8.22)      ($3.28)

</Table>


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

                                        3


<Page>

<Table>
<Caption>


                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                             (Dollars in thousands)

                                                              June 30,        December 31,
                                                                2005              2004
                                                             -----------       -----------
<S>                                                              <C>               <C>
ASSETS
Current Assets:
  Cash & Cash Equivalents                                        $2,260            $9,627
  Accounts Receivable, net                                        1,456               639
  Prepayments & Other Assets                                         96                83
                                                                -------           -------
      Total Current Assets                                        3,812            10,349

Other Long Term Assets:
  Gas and Oil Properties, Net                                    16,976               670
  Property, Plant and Equipment, net                              2,190                 0
  Restricted Cash - Escrow                                        2,936             2,500
  Intangible Asset                                                   45                45
  Other Long Term Assets                                            522               518
                                                                -------           -------
      Total Other Assets                                         22,669             3,733

                                                                -------           -------
TOTAL ASSETS                                                    $26,481           $14,082
                                                                =======           =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
  Accounts Payable and Accrued Expenses                            $502              $769
  Accrued Taxes                                                     107                92
  Note Payable                                                   13,926                 0
  Other Current Liabilities                                         410               741
                                                                -------           -------
          Total Current Liabilities                              14,945             1,602

Deferred Gain on Energy Contract                                  1,403             1,534
Unrealized Loss on Energy Contract - at market                    6,944             3,424
Long Term Liability                                               2,479             2,479
Minority Interest in Subsidiary                                     262               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 - 571,364 and 557,945
      shares, respectively                                            6                 6
  Additional Paid-in Capital                                    (21,237)          (21,475)
  Accumulated Earnings                                           21,679            26,293
                                                                -------           -------
          Total Stockholders' Equity                                448             4,824

                                                                -------           -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                      $26,481           $14,082
                                                                =======           =======

</Table>
 (The accompanying notes are an integral part of these consolidated statements.)

                                        4

<Page>

<Table>
<Caption>


                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                             (Dollars in thousands)


                                                                      Six Months Ended
                                                                          June 30,
                                                                      2005        2004
                                                                      ----        ----
<S>                                                                   <C>           <C>
Net cash flow from operating activities:
  Net loss                                                           ($4,613)     ($2,002)
  Adjustments to reconcile net loss to net
  cash provided by (used in) operating activities:
       Minority interest                                                  45           (2)
       Extraordinary gain, net of tax                                      0         (278)
       Unrealized loss on the mark-to-market of energy contract        3,520        2,485
       Amortization of deferred gain on energy contract                 (132)        (132)
       Non-cash compensation expense                                      57           86
       Depreciation, depletion and amortization                          699            0
       Increase in accounts receivable                                  (816)        (366)
       (Increase) decrease in prepaids and other assets                 (452)       1,220
       Increase (decrease) in accounts payable and
         accrued expenses                                               (269)         110
       Increase (decrease) in taxes accrued                               15          (13)
       Decrease in miscellaneous and other liabilities                   (69)        (953)
                                                                     -------      -------
    Net cash provided by (used in) operating activities               (2,015)         155

Net cash provided by (used in) investing activities:
        Acquisition of Benton Falls                                   (2,220)           0
        Investment in oil and gas properties                         (16,975)           0
        Investment in HoustonStreet                                       (2)           0
        Consolidation of HoustonStreet                                     0          393
                                                                     -------      -------
    Net cash provided by (used in) investing activities              (19,197)         393

Net cash provided by (used in) financing activities:
       Stock option exercise                                             180            0
       Convertible note                                               13,665            0
       Reacquired capital stock and options                                0       (1,074)
                                                                     -------      -------
    Net cash provided by (used in) financing activities               13,845       (1,074)

Net decrease in cash and cash equivalents                             (7,367)        (526)
Cash and cash equivalents, beginning of period                         9,627        7,469
                                                                     -------      -------
Cash and cash equivalents, end of period                              $2,260       $6,943
                                                                     =======      =======
Supplemental disclosure of cash flow information:
 Cash paid during the period for income taxes                        $    27          $12
                                                                     -------      -------

</Table>

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

                                        5


<Page>


                   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  June  30,  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 June 30,
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.  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,  LLC  ("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,  the  Company formed  Nacogdoches  Power,  LLC
("Nacogdoches  Power"), a New Hampshire limited liability  company,
as  a  wholly  owned  subsidiary.  Nacogdoches Power  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  gas-fired
power  plant.   The  project received its  air  quality  permit  in
December  2002, which is effective through December  7,  2005.   An
additional eighteen-month extension to the permit may be  requested
by  Nacogdoches Power.  A wastewater discharge permit is  currently
effective through August 1, 2006.  Nacogdoches Power 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  seeking
to  enter  into power off-take contracts, although 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, type and availability of any such financing
has not been determined.

                                 6

<Page>

  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  Resources Corporation ("Sonerra") an independent  oil  and
gas exploration, development and operating company.

  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, 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  would  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  fifteen
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 funded the development of six wells.   The  net
revenue  interest  in  each  of these six  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
funded 100% of the cost of developing the first four wells and  has
a   90%  working  interest   in  these  wells.   This  means   that
Nacogdoches Gas bears 90% of the operating costs of the  wells  and
receives 69.3% of the net revenues from the wells.  Nacogdoches Gas
funded 85% of the cost of developing the next two wells and  has  a
76.5% working interest in those wells.  This means that Nacogdoches
Gas  bears  76.5%  of the operating costs of these  two  wells  and
receives 58.9% of the net revenues from the wells.

  The  first  of  the  six  wells, Round  Mountain,  a  James  Lime
horizontal natural gas well, began production in January  2005  and
through the end of June 2005 has produced 211 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 June 2005 has produced approximately 180 million  cubic
feet  of  natural gas.  The fourth well, Whirlwind,  a  James  Lime
horizontal natural gas well, began production in May 2005  and  has
produced  approximately 79 million cubic feet of natural gas.   The
fifth  and sixth wells, Looking Glass and Thunder Chief, both James
Lime horizontal natural gas wells, are being developed.

  The  third  well developed under its joint development  agreement
with Sonerra, Painted Horse, was drilled as a vertical well.  After
initial  promising flow rates, this well did not produce commercial
amounts of natural gas.  There is currently no production from this
well,  and Sonerra and Nacogdoches Gas are evaluating their options
for  this  well.   These  options  include  completion  in  another
interval, which would require additional funding, or abandonment of
the  well.   The estimated cost of this well is approximately  $2.1
million.   Due  to  the impairment of this well,  the  Company  has
written  off the cost of this well and recorded exploration expense
of  approximately  $2.1 million.  This amount is reflected  in  the
accompanying  financial statements. The cost of this well  will  be
included in the total costs that are to be recovered from producing
wells before BayCorp's net working interest is reduced from 90%  to
50%  in  accordance  with  the  joint  development  agreement  with
Sonerra.

  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.  Nacogdoches Gas acquired these assets in accordance  with
the terms of the January 7, 2005

                                 7

<Page>

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%.  The Company accounted for  this  acquisition
using purchase accounting.

  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. ("Benton Falls"),  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 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  July
2005  through December 2005 (based on projected monthly generation)
is  approximately $52.77 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 59.8% 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.

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
"First  Note")  and  a 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

                                 8

<Page>

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  First Note) into shares  of  BayCorp's  common
stock,  $.01 par value at a price of $14.04 per share.   The  First
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  First Note may be accelerated in the event of  a  material
event of default.

  On  May  24,  2005,  the  Company and all  of  its  wholly  owned
subsidiaries, entered into a $10,000,000 multiple-draw  convertible
debt  facility  (the  "Second Note") and an  Amended  and  Restated
Pledge  Agreement (the "Amended Pledge Agreement") with  the  Sloan
Group.  Any draws under the Second Note, which will accrue interest
at  8% and be due on December 15, 2005, are 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.

  In  addition to BayCorp, the borrowers under the First and Second
Notes  include  the following subsidiaries of BayCorp:  GBH  Maine,
Great  Bay  Power  Marketing, Great Bay  Hydro,  BayCorp  Ventures,
Nacogdoches  Power and Nacogdoches Gas.  Under the  Amended  Pledge
Agreement,  BayCorp pledged its equity interests in GBH  Maine  and
Nacogdoches  Gas,  GBH Maine pledged its equity  interests  in  GBH
Benton  and  Benton  Falls,  and  GBH  Benton  pledged  its  equity
interests  in  Benton Falls.  Nacogdoches Gas, GBH  Maine  and  GBH
Benton  pledged any equity interest that they may obtain  in  other
entities  while  the debt is outstanding, and Nacogdoches  Gas  and
Nacogdoches Power pledged certain of their contract rights.

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 has acquired working  interests  in
natural  gas and oil producing wells.  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.

                                 9

<Page>

  In   January  2003,  the  Financial  Accounting  Standards  Board
("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.

  Energy Marketing

  Forward  contracts, including the purchased power  contract  with
Unitil  dated  as  of April 1, 2003 (the "Unitil  PPA"  or  "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
$57,000  in the six months ended March 31, 2005 and 2004  based  on
the  fair  value  of options granted determined  using  the  Black-
Scholes  option pricing model.  The Company did not  grant  options
during  the six months ended June 30, 2005 or during the six months
ended June 30, 2004.

  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

                                10

<Page>

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 or state regulators enact new plugging and
abandonment requirements.

NOTE D - COMMITMENTS AND CONTINGENCIES

Purchased Power Agreements
--------------------------

  Great  Bay was party to a purchased power contract, dated  as  of
April  1, 1993, 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
Federal Energy Regulatory Commission ("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 Emerging  Issues  Task
Force ("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 $6.9 million as of June 30, 2005  and  was
negative  $3.4 million as of December 31, 2004.  The deferred  gain
on  the  contract  was $1.4 million as of June 30,  2005  and  $1.5
million  as  of December 31, 2004.  These amounts are reflected  in
the Company's balance sheet.

                                11

<Page>

  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.

                                          Six Months ended
                                           June 30, 2005
                                          ----------------
                                           (in thousands)
       Oil and Gas properties:
       Properties subject to depletion         $ 12,192
       Unproved properties                        3,474
                                                -------
         Total                                   15,666
       Accumulated depletion                        689
                                               --------
         Net                                    $14,977
                                                =======

  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.

                                12

  <Page>



  Quantities of Proved Natural Gas Reserves (Mmcf):

     Balance December 31, 2004                         149
       Revisions                                         0
       Extensions, discoveries and additions             0
       Purchases                                     7,068
       Sales                                             0
       Production                                     (369)
                                                     -----
     Balance, June 30, 2005                          6,848

NOTE F -  INVESTMENT IN HOUSTONSTREET

  A  recapitalization at HoustonStreet was completed in the  second
quarter  of  2004 and as a result, BayCorp owns shares representing
approximately   59.8%   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
     --------------                        --------------
                                           (in thousands)

     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
Company   distributed  approximately  $123,622,000   to   tendering
stockholders and option holders.

  As  of  June  30, 2005 there were 571,364 shares outstanding  and
options to purchase 199,119 shares.

  BayCorp has never paid cash dividends on its common stock.

                                13

<Page>


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,
GBH  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 GBH 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.


  <Table>
  <Caption>

                          Electri-
 BayCorp Holdings, Ltd      city
 As of and for the six     Genera-      Oil and
      months ended          tion          Gas      Houston-                  Inter-
        June 30              and        Produc-     Street                  company
        ($000's)           Trading       Tion         (1)       Other         Elim    Total
  -------------------      -------      -------     -------     ------      -------   -----
2005
----
<S>                         <C>          <C>         <C>         <C>       <C>        <C>
Revenues                    $2,994       $2,327      $513            $0         $0    $5,834
Operating Expenses           6,218        3,223       411           767          0    10,619
Segment Net Income (Loss)   (3,502)      (1,117)       67             6        (67)   (4,613)
Total Assets                12,820       18,640       676        31,551    (37,206)   26,481
                            ------       ------      ----        ------    -------    ------
2004
----
Revenues                    $2,321            -      $156            $0         $0    $2,477
Operating Expenses           4,823            -       162           819       (270)    5,534
Segment Net Loss            (2,489)           -        (3)          487          3     2,002
Total Assets                 5,871            -       515        19,431    (14,166)   11,651
                            ------       ------      ----        ------    -------    ------

</Table>

(1) BayCorp began consolidating HoustonStreet as of May 1, 2004.  See "Note A.
The Company."


                                       14

<Page>


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.

  In  May 2005, the FASB issued FASB Statement No. 154, "Accounting
Changes and Error Corrections, a replacement of APB Opinion No.  20
and  FASB Statement No. 3" (SFAS No. 154).  Previously, APB No. 20,
"Accounting Changes" and SFAS No. 3, "Reporting Accounting  Changes
in  Interim  Financial Statements" required the  inclusion  of  the
cumulative effect of changes in accounting principle in net  income
of  the  period of the change.  SFAS No. 154 requires companies  to
recognize  a  change  in accounting principle, including  a  change
required  by  a new accounting pronouncement when the pronouncement
does not include specific transition provisions, retrospectively to
prior  periods' financial statements.  The Company will assess  the
impact  of  a  retrospective application of a change in  accounting
principle in accordance with SFAS No. 154 when such a change arises
after the effective date of January 1, 2006.

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

Overview

  BayCorp  derived  its  revenues primarily  through  energy  sales
activities by Great Bay Power Marketing, Great Bay Hydro, GBH Maine
and  Nacogdoches Gas in the first six months of 2005.  In the first
six  months  of  2004, the Company derived its  revenues  from  six
months  of operation at Great Bay Power Marketing, three months  of
operation  at  Great  Bay Hydro and two months  of  operation  from
HoustonStreet.

  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

                                15

<Page>

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 Benton  Falls,  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.

  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  would
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
fifteen  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 six wells.   The  net
revenue  interest  in  each  of these six  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
funded 100% of the cost of developing the first four wells and  has
a   90%  working  interest   in  these  wells.   This  means   that
Nacogdoches Gas bears 90% of the operating costs of the  wells  and
receives 69.3% of the net revenues from the wells.  Nacogdoches Gas
funded 85% of the cost of developing the next two wells and  has  a
76.5% working interest in those wells.  This means that Nacogdoches
Gas  bears  76.5%  of the operating costs of these  two  wells  and
receives 58.9% of the net revenues from the wells.

  The  first  of  the  six  wells, Round  Mountain,  a  James  Lime
horizontal natural gas well, began production in January  2005  and
through the end of June 2005 has produced 211 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 June 2005 has produced approximately 180 million  cubic
feet  of  natural gas.  The fourth well, Whirlwind,  a  James  Lime
horizontal natural gas well, began production in May 2005  and  has
produced  approximately 79 million cubic feet of natural gas.   The
fifth  and sixth wells, Looking Glass and Thunder Chief, both James
Lime horizontal natural gas wells, are being developed.

  The  third  well developed under its joint development  agreement
with Sonerra, Painted Horse, was drilled as a vertical well.  After
initial  promising flow rates, this well did not produce commercial
amounts of natural gas.  There is currently no production from this
well,  and Sonerra and Nacogdoches Gas are evaluating their options
for  this  well.   These  options  include  completion  in  another
interval, which will require additional funding, or abandonment  of
the  well.   The estimated cost of this well is approximately  $2.1
million.   Due  to  the impairment of this well,  the  Company  has
written  off the cost of this well and recorded exploration expense
of approximately $2.1 million.  This amount is

                                16

<Page>

reflected  in the accompanying financial statements.  The  cost  of
this  well  will  be included in the total costs  that  are  to  be
recovered  from  producing  wells  before  BayCorp's  net   working
interest  is reduced from 90% to 50% in accordance with  the  joint
development agreement with Sonerra.

  Expenses  for  the  first six months of 2005 and  2004  primarily
consisted of the cost of purchased power, production related costs,
general and administrative costs and unrealized losses for the mark
to market of the Unitil PPA.

  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 F.  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: Second Quarter of 2005 Compared to the
Second Quarter of 2004
-------------------------------------------------------------

Operating Revenues

  BayCorp's   operating   revenues   increased   by   approximately
$2,031,000 to $3,474,000 in the second quarter of 2005 as  compared
to  $1,443,000 in the second quarter of 2004.  Total  revenues  for
the   second  quarter  of  2005  included  approximately   $996,000
generated  from Great Bay Power Marketing's long-term  power  sales
contract with Unitil and approximately $17,000 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  $583,000  and  the  related  cost   of   sales   was
approximately  $566,000.  In addition, in  the  second  quarter  of
2005,  Great Bay Hydro generated revenues of approximately $389,000
and GBH Maine generated revenues of approximately $406,000 from the
sale  of  electricity.   Nacogdoches  Gas  generated  revenues   of
approximately  $1,397,000  from  the  sale  of  natural   gas   and
HoustonStreet   generated   revenues  of  approximately   $270,000.
Operating revenues in the second quarter of 2004 included Great Bay
Power  Marketing  revenues of approximately $1,004,000,  Great  Bay
Hydro revenues of approximately $283,000 and HoustonStreet revenues
of approximately $150,000.

  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 second quarters of both 2005 and  2004.   The
cost  of  power purchased to supply this contract was approximately
5.83 cents per kWh for the second quarter of 2005 and approximately
5.05  cents per kWh for the second quarter of 2004.  For the second
quarter of 2005, the Company realized an average selling price  for
electricity  generated and sold by Great Bay Hydro of approximately
5.84 cents per kWh.

Expenses

  Great  Bay  Power Marketing purchases power to satisfy its  power
supply  obligation under the Unitil PPA.  Purchased power  expenses
increased by approximately $155,000, or 15.5%, to $1,153,000 in the
second  quarter  of  2005  as compared to $998,000  in  the  second
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

                                17

<Page>

approximately $1,399,000 in the second quarter of 2005 as  compared
to  a  net unrealized loss of approximately $716,000 in the  second
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
second  quarter of 2004 and have continued to rise into the  second
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.  Accordingly, the price of power  in  NEPOOL  is
highly influenced by the price of natural gas.

  Production   and   transmission   expenses   were   approximately
$2,317,000  in  the  second quarter of 2005.   Production  expenses
associated  with  Nacogdoches  Gas  operations  were  approximately
$2,300,000;  included  in  production  expenses  was  approximately
$2,115,000  for exploration expense related to Painted  Horse,  the
third  well  developed under its joint development  agreement  with
Sonerra.   After initial promising flow rates, this  well  did  not
produce  commercial amounts of natural gas.  There is currently  no
production  from  this well, and Sonerra and  Nacogdoches  Gas  are
evaluating  their  options for this well.   These  options  include
completion  in  another  interval, which would  require  additional
funding,  or  abandonment  of the well.  Under  successful  efforts
accounting,  the  Company has expensed impairment costs  associated
with this well.

  Administrative  and  general  expenses  increased   approximately
$219,000,  or 37.4%, to $805,000 in the second quarter of  2005  as
compared  to $586,000 in the second quarter of 2004.  This increase
was  primarily attributable to administrative and general  expenses
associated  with  the  Company's  operations  at  Nacogdoches  Gas,
Nacogdoches   Power   and   at  HoustonStreet.    There   were   no
administrative and general expenses associated with Nacogdoches Gas
and Nacogdoches Power in the second quarter of 2004, and two months
of  HoustonStreet expenses were recorded in the second  quarter  of
2004.

  Depreciation,   depletion  and  amortization  was   approximately
$429,000  in  the second quarter of 2005 and reflects approximately
$399,000  in  depletion  expense of Nacogdoches  lease  acquisition
costs  and development costs for the second 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.   In  addition,  the
Company  recorded approximately $30,000 for depreciation  of  plant
and  equipment  at  the Company's hydro facilities  in  the  second
quarter  of  2005.   There  were  no  depletion,  depreciation   or
amortization expenses in the second quarter of 2004.

  Taxes  other  than  income  increased approximately  $44,000,  to
$61,000 in the second quarter of 2005 as compared to $17,000 in the
second  quarter of 2004 primarily due to Great Bay  Hydro  and  GBH
Maine  property  taxes.  There was no property tax expense  in  the
second quarter of 2004.

  The Company recorded other deductions of approximately $94,000 in
the  second  quarter  of  2005  as  compared  to  other  income  of
approximately $711,000 in the second quarter of 2004.  Included  in
other  deductions  in the second quarter of 2005 was  approximately
$225,000  in  interest expense associated with the  debt  financing
provided  by  the  Sloan  Group.  See  "Note  B.  Debt  Financing."
Offsetting this expense was other income of approximately  $126,000
from  a  Nuclear  Electric  Insurance  Limited  ("NEIL")  insurance
distribution received in the second quarter of 2005.  Other  income
in  the  second quarter of 2004 primarily reflected receipt by  the
Company of approximately $672,000 for closing adjustments and other
costs specific to the Company's sale of its interests in Seabrook.

                                18

<Page>

  In  the  second  quarter  of  2004,  the  Company  recognized  an
extraordinary   gain   of  $278,000  upon  the   consolidation   of
HoustonStreet.   As  of  May  1,  2004,  BayCorp's   ownership   in
HoustonStreet  was 59.7%, and 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.

Net Loss

  As a result of the above factors, for the second quarter of 2005,
the  Company  recorded a net loss of approximately  $2,809,000,  or
$4.98  per  share,  as  compared to  net  income  of  approximately
$95,000, or $0.16 per share, for the second quarter of 2004.

Results of Operations: First Six Months of 2005 Compared to the
First Six Months of 2004
---------------------------------------------------------------

Operating Revenues

  BayCorp's   operating   revenues   increased   by   approximately
$3,357,000  to  $5,834,000  in the first  six  months  of  2005  as
compared  to  $2,477,000 in the first six months  of  2004.   Total
revenues  for  the first six months of 2005 included  approximately
$1,981,000  generated  from Great Bay Power  Marketing's  long-term
power  sales contract with Unitil and approximately $42,000 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 $1,096,000 and the related  cost
of  sales was approximately $1,054,000.  In addition, in the  first
six  months  of  2005,  Great  Bay  Hydro  generated  revenues   of
approximately  $533,000,  and  GBH  Maine  generated  revenues   of
approximately  $438,000 from the sale of electricity.   Nacogdoches
Gas generated revenues of approximately $2,327,000 from the sale of
natural  gas, and HoustonStreet generated revenues of approximately
$513,000.  Consolidated operating revenues in the first six  months
of   2004  were  approximately  $2,038,000  from  Great  Bay  Power
Marketing,  $283,000  from  Great  Bay  Hydro  and  $156,000   from
HoustonStreet.

  The  Company  realized an average selling price  for  electricity
sold under the Unitil sales contract of 5.03 cents per kWh for  the
first  six  months  of  both 2005 and  2004.   The  cost  of  power
purchased to supply this contract was approximately 5.97 cents  per
kWh  for the first six months of 2005 and approximately 5.38  cents
per kWh for the first six months of 2004.  The Company realized  an
average  selling price for electricity generated and sold by  Great
Bay  Hydro  of approximately 5.93 cents per kWh and 5.16 cents  per
kWh  for the six months ended June 30, 2005 and 2004, respectively,
and  Great  Bay  Hydro's cost of generating power was approximately
3.14  cents per kWh and 1.95 cents per kWh for the six months ended
June 30, 2005 and 2004, respectively.  For the first six months  of
2005, the Company realized an average selling price for electricity
generated and sold by GBH Maine of approximately 5.74 cents per kWh
and  GBH  Maine's  cost of generating power was approximately  2.02
cents per kWh.

Expenses

  Great  Bay  Power Marketing purchases power to satisfy its  power
supply  obligation under the Unitil PPA.  Purchased power  expenses
increased by approximately $222,000, or 10.4%, to $2,351,000 in the
first six months of 2005 as compared to $2,129,000 in the first six
months of 2004.

                                19

<Page>

  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
$3,388,000  in the first six months of 2005 as compared  to  a  net
unrealized loss of approximately $2,353,000 in the first six months
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  six
months of 2004 and have continued to rise into the first six months
of  2005 primarily due to increases in the forward price of natural
gas.

  Production   and   transmission   expenses   were   approximately
$2,528,000  in  the  first  six  months  of  2005  as  compared  to
approximately $22,000 in the first six months of 2004.   Production
expenses   associated   with  Nacogdoches   Gas   operations   were
approximately $2,428,000 in the first six months of 2005;  included
in production expenses was approximately $2,115,000 for exploration
expense related to the impairment of Painted Horse, the third  well
developed  under  its  joint development  agreement  with  Sonerra.
Production  expenses in the first six months of 2004 were  specific
to Great Bay Hydro operations.

  Administrative  and  general  expenses  increased   approximately
$532,000, or 53.2%, to $1,532,000 in the first six months  of  2005
as  compared to $1,000,000 in the first six months of  2004.   This
increase  was primarily attributable to administrative and  general
expenses  associated with the Company's operations  at  Nacogdoches
Gas,  Nacogdoches  Power  and  at  HoustonStreet.   There  were  no
administrative and general expenses associated with Nacogdoches Gas
and  Nacogdoches  Power in the first six months  of  2004  and  two
months  of  HoustonStreet expenses were recorded in the  first  six
months of 2004.

  Depreciation,    depletion   and   amortization    expense    was
approximately  $699,000  in  the  first  six  months  of  2005  and
reflected  approximately $669,000 in depletion of  Nacogdoches  Gas
lease  acquisition costs and development costs for  the  first  six
months of 2005.  Under the successful efforts method of accounting,
lease  acquisition costs and all development costs are capitalized.
The  provision for depletion is based upon the units of  production
method.   In  addition, the Company recorded approximately  $30,000
for  depreciation  of  plant and equipment at the  Company's  hydro
facilities  in  the  first  six  months  of  2005.   There  was  no
depletion,  depreciation or amortization expense in the  first  six
months of 2004.

  Taxes  other  than  income  increased approximately  $91,000,  to
$121,000 in the first six months of 2005 as compared to $30,000  in
the  first six months of 2004 primarily due to Great Bay Hydro  and
GBH Maine property taxes.  There was no property tax expense in the
first six months of 2004.

  The Company recorded other deductions of approximately $8,000  in
the  first  six  months  of 2005 as compared  to  other  income  of
approximately  $775,000 in the first six months of 2004.   Included
in   other  deductions  in  the  first  six  months  of  2005   was
approximately $261,000 in interest expense associated with the debt
financing  provided  by  the  Sloan  Group.   See  "Note  B.   Debt
Financing."    Offsetting  this  expense,  was  other   income   of
approximately $144,000 from a NEIL insurance distribution  received
in  the  first  six  months of 2005 and an  accrual  adjustment  of
approximately  $92,000.  Other income in the first  six  months  of
2004  primarily  reflected  receipt  by  the  Company  of  one-time
payments  totaling  approximately $686,000 for closing  adjustments
and other costs specific to the Company's sale of its interests  in
Seabrook in November 2002.

  Income  tax  income  in  the first six months  of  2005  reflects
receipt  by the Company of $225,000 from the State of New Hampshire
for overpayment of prior year state income taxes.

                                20

<Page>

  In  the  first  six  months of 2004, the  Company  recognized  an
extraordinary   gain   of  $278,000  upon  the   consolidation   of
HoustonStreet.

Net Loss

  As  a  result of the above factors, for the first six  months  of
2005,  the Company recorded a net loss of approximately $4,613,000,
or  $8.22  per  share, as compared to a net loss  of  approximately
$2,002,000, or $3.28 per share, for the first six months of 2004.

Liquidity and Capital Resources

  As of June 30, 2005, BayCorp had approximately $2,260,000 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 total restricted cash is reflected as a  long
term  asset in the Company's financial statement.  The Company also
had  approximately $522,000 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 GBH Maine, proceeds from  the
sale  of natural gas and oil by Nacogdoches Gas, and advances taken
on  the  Second  Note facility with Sloan, will  be  sufficient  to
enable the Company and its wholly owned subsidiaries to meet  their
cash requirements for operations in 2005.

  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.   On
May 24, 2005, the Company and all of its wholly owned subsidiaries,
entered  into a $10,000,000 multiple-draw convertible debt facility
and  an Amended and Restated Pledge Agreement with the Sloan Group.
The  total  debt, including any draws under the Second Note,  which
will  accrue  interest at 8% and be due on December  15,  2005,  is
convertible 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 First or Second Note) into
shares of the Company's common stock, $.01 par value, at a price of
$14.04  per  share.  The Notes do not allow BayCorp to  prepay  the
debt  and  provides for a 2% premium on the interest  rate  in  the
event of a default.  Payment 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 First
or  Second Note is required on December 15, 2005, the Company would
need to seek additional financing.  There is no assurance that  the
Company  or its subsidiaries would be able to obtain such financing
or  that  the terms on which any additional financing is  available
would be acceptable.

  The  Company had a net loss in the first six months  of  2005  of
approximately  $4,613,000.  There was  a  non-cash  charge  for  an
unrealized  loss  on  the  mark-to-market  of  the  Unitil  PPA  of
approximately  $3,520,000 and a non-cash  recognition  of  deferred
gain  on  the Unitil PPA of approximately $132,000.  The  value  of
this  contract is based on current projections of power prices over
the life of the

                                21

<Page>

contract.   Forward  power prices increased during  the  first  six
months  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 frequently 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  $57,000  for  the  variable  accounting  of  certain
employee  stock  options, approximately $45,000  for  HoustonStreet
minority  interest  and  approximately $699,000  for  depreciation,
depletion and amortization.

  An  increase  in accounts receivable in the first six  months  of
2005  of  approximately  $816,000  was  primarily  attributable  to
accounts   receivable   at  Nacogdoches  Gas.    An   increase   of
approximately  $452,000 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 GBH Maine.  An increase  in  accounts
payable   and  accrued  expenses  of  approximately  $269,000   was
primarily  attributable to an increase in accounts  payable  as  of
June 30, 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  six  months  of 2005 also included  investments  by
Nacogdoches Gas of approximately $17,000,000 for interests  in  six
oil and natural gas wells.  See "Note A. The Company."

  The  Company had no long-term contractual obligations as of  June
30, 2005.

  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 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.

                                22

<Page>

  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.   The Company's balance sheet as of  June  30,  2005
reflects  short-term  and  long-term liabilities  of  $400,000  and
$2,479,000, respectively, for the estimated remaining cost of  FERC
compliance.   The  Company  expects to complete  the  FERC  license
requirements within those amounts.  For the six months  ended  June
30,  2005,  the  Company  spent  approximately  $328,000  for  FERC
compliance.

  In  November 2004, BayCorp formed Nacogdoches Gas.  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
would 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
fifteen  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 funded the development of six wells.   The  net
revenue  interest  in  each  of these six  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
funded 100% of the cost of developing the first four wells and  has
a 90% working interest in these wells.  This means that Nacogdoches
Gas  bears  90%  of the operating costs of the wells  and  receives
69.3%  of the net revenues from the wells.  Nacogdoches Gas  funded
85%  of  the cost of developing the next two wells and has a  76.5%
working  interest in those wells.  This means that Nacogdoches  Gas
bears  76.5% of the operating costs of these two wells and receives
58.9% of the net revenues from the wells.

  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.

  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.

                                23

<Page>

  In April 2005, Nacogdoches Gas funded the acquisition of certain
natural gas production assets in Nacogdoches County, Texas formerly
owned by SunStone for approximately $3.4 million.  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 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
such cash, together with the anticipated proceeds from the sale  of
electricity by Great Bay Power Marketing, Great Bay Hydro  and  GBH
Maine, proceeds from the sale of natural gas and oil by Nacogdoches
Gas,  and  advances taken on the Second Note facility  with  Sloan,
will  be  sufficient  to enable the Company and  its  wholly  owned
subsidiaries  to  meet their cash requirements  for  operations  in
2005.   If  payment  on  the First or Second Note  is  required  on
December  15,  2005,  the  Company would need  to  seek  additional
financing.   There  is  no  assurance  that  the  Company  or   its
subsidiaries  would be able to obtain such financing  or  that  the
terms  on  which  any  additional financing is available  would  be
acceptable.   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.  Please see
"Note C - Summary of Significant Accounting Policies" above.

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

                                24

<Page>

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 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.  Further, in particular,
there  can  be  no  assurance  that  the  Company's  oil  and   gas
exploration  activities generally or any particular  well  drilling
activity will be productive or will produce sufficient gas and  gas
sales  revenues  to  be  profitable  or  to  return  the  Company's
investment.

  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 June 30, 2005, BayCorp had  approximately
$5.2  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 the Sloan Group.   On  May
24,  2005,  the  Company  entered into a $10,000,000  multiple-draw
convertible debt facility with the Sloan Group and as of  June  30,
2005, the Company had drawn approximately $3.4 million against this
debt  facility.   On July 12, 2005, the Company drew  approximately
$3.2  million. The total 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 these financings to finance the acquisition  of
Benton  Falls  by  GBH  Maine and GBH Benton  and  to  finance  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, and advances taken
on  the  Second Note, will be sufficient to enable the Company  and
its  wholly owned subsidiaries to meet their cash requirements  for
operations  in  2005.   If payment on the First or Second  Note  is
required  on  December 15, 2005, the Company  would  need  to  seek
additional financing.  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.

                                25

<Page>

  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  GBH Maine 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 a wastewater
discharge  permit  issued by the Texas Commission on  Environmental
Quality.   Extensions of those permits and additional environmental
permits  will  be required prior to the start of operation  of  the
project.   In  addition, prior to operation  of  the  Sterne  Power
project, Nacogdoches Power may 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

                                26

<Page>

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.

  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.

                                27

<Page>

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
six  months  of  2005  and  2004  of approximately  $3,388,000  and
$2,353,000, respectively, on its forward firm energy contract.

  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 June
30, 2005 and 2004 and the unrealized loss for those periods.

                        June 30,  2005    June 30, 2004
                        --------------    -------------
                             (Dollars in thousands)
Fair Value                 ($6,944)          ($2,481)
Unrealized Gain (Loss)     ($3,520)          ($2,485)

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

                                28

<Page>

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.

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 quarter ended June 30, 2005:



  <Table>
  <Caption>

                                               Total Number of
                                               Shares Purchased         Maximum Number
                                                  as Part of          of Shares that May
                                Average       Publicly Announced       Yet Be Purchased
                 Shares          Price              Plans             Under the Plans or
   Period      Repurchased     Per Share         or Programs             Programs (1)
   ------      -----------     ---------      ------------------       -----------------
     <S>           <C>            <C>                <C>                      <C>
  April 1 -
  June 30,
    2005            0             --                  --                    100,024

</Table>



(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 4.  Submission of Matters to a Vote of Security Holders
------------------------------------------------------------

  The  Company held its Annual Meeting of Stockholders on  May  17,
2005.    Proxies  for  the  meeting  were  solicited  pursuant   to
Regulation  14A, and there were no solicitations in  opposition  to
management's  nominees  for  Directors.   All  such  nominees  were
elected.   At the Annual Meeting, the following matters were  voted
on:
                                29

<Page>

  1.  Six  members were elected to the Board of Directors to  serve
      until  the next Annual Meeting of Stockholders of the Company
      and  until  their successors are duly elected and  qualified.
      The  following table sets forth the number of votes cast  for
      and withheld for each nominee for Director.

                  Name                   For         Withheld
                  ----                   ---         --------
   Anthony M. Callendrello             533,931        12,723
   Alexander Ellis                     545,094          1,560
   Stanley I. Garnett                  545,094          1,560
   Frank W. Getman Jr.                 533,931        12,723
   James S. Gordon                     539,578          7,076
   Thomas C. Leonard                   545,094          1,560

  2.  The stockholders of the Company ratified the selection by
      the Audit Committee of Vitale, Caturano & Company, PC as the
      Company's independent auditors by a vote of 546,090 shares
      in favor of the proposal, 61 shares voted against the
      selection, and 503 shares abstained.


Item 6.  Exhibits
-----------------

  See Exhibit Index.







                                30


<Page>

                            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.


August 5, 2005             /s/  Frank W. Getman Jr.
                         -------------------------------------
                           Frank W. Getman Jr.
                           President and Chief Executive Officer
                           and Principal Financial Officer





                                31

<Page>

                           EXHIBIT INDEX



Exhibit No. Description
----------- -----------

    3.1     Certificate  of Incorporation of BayCorp  Holdings,
            Ltd.,  as  amended,  filed as Exhibit  3.1  to  the
            Company's Annual Report on Form 10-K (File  No.  1-
            12527) on March 31, 2005 and incorporated herein by
            reference.

    3.2     By-laws of BayCorp Holdings, Ltd., filed as Exhibit
            3.2  to  the Registration Statement on Form S-4  of
            BayCorp Holdings, Ltd. (Registration Statement 333-
            3362)  filed  on  April 11, 1996  and  incorporated
            herein by reference.

   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 June 30, 2005.






                                32