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   September 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


                                          Outstanding at
            Class                        November 1, 2005
_____________________________       ___________________________
Common Stock, $0.01 Par Value                 571,364
          per Share


                                1

<Page>
                              INDEX


PART I - FINANCIAL INFORMATION:

Item 1 - Financial Statements:

Consolidated Statements of Operations -
  Three and Nine Months Ended September 30, 2005
  and 2004. . . . . . . . . . . . . . . . . . . . . . .         3

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

Consolidated Statements of Cash Flows -
  Nine Months Ended September 30, 2005
  and 2004. . . . . . . . . . . . . . . . . . . . . . .         5

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

Item 2 - Management's Discussion and Analysis
  of Financial Condition and Results of Operations  . .        16

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

Item 4 - Controls and Procedures. . . . . . . . . . . .        29

PART II - OTHER INFORMATION:

Item 2 - Unregistered Sales of Equity Securities
  and Use of Proceeds . . . . . . . . . . . . . . . . .        30

Item 5 - Other Information  . . . . . . . . . . . . . .        30

Item 6 - Exhibits . . . . . . . . . . . . . . . . . . .        31

Signatures. . . . . . . . . . . . . . . . . . . . . . .        32

Exhibit Index . . . . . . . . . . . . . . . . . . . . .        33


                                2

<Page>

PART I - FINANCIAL INFORMATION

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


<Page>
<Table>
<Caption>

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

                                                Three Months Ended   Nine Months Ended
                                                  September 30,        September 30,
                                                  _____________        _____________
                                                  2005      2004        2005       2004
                                                  ____      ____        ____       ____
<S>                                            <C>        <C>        <C>        <C>
Operating Revenues                              $4,098     $1,442      $9,932    $3,919

Operating Expenses
  Purchased Power                                1,700        897       4,051     3,026
  Unrealized Loss on Energy Contracts            5,490        648       8,878     3,000
  Production and Transmission                      268         22       2,796        22
  Administrative & General                       1,128        520       2,660     1,532
  Depreciation, Depletion and Amortization         521          0       1,220         0
  Taxes Other Than Income                           50         60         171        97
                                               _______    _______    ________   _______
      Total Operating Expenses                   9,157      2,147      19,776     7,677

Operating Loss                                  (5,059)      (705)     (9,844)   (3,758)

Other Income (Deductions)
  Interest and Dividend Income                      34         46         105       146
  Other Income (Deductions)                       (347)       440        (426)    1,110
                                               _______    _______    ________   _______
      Total Other Income (Deductions)             (313)       486        (321)    1,256

Loss Before Income Taxes, Minority Interest
  And Extraordinary Item                        (5,372)      (219)    (10,165)   (2,502)
Income Taxes                                       (41)       (13)        184       (13)
Minority Interest                                  (14)       (18)        (59)      (16)
                                               _______    _______    ________   _______
Loss Before Extraordinary Item                  (5,427)      (250)    (10,040)   (2,531)
Extraordinary Item                                   0          0           0       278
                                               _______    _______    ________   _______
Net Loss                                       ($5,427)     ($250)   ($10,040)  ($2,253)
                                               =======    =======    ========   =======

Weighted Average Shares Outstanding -
  Basic and Diluted                            571,364    560,612     564,679   594,143
Loss Per Share before Extraordinary Item -
  Basic and Diluted                             ($9.50)   ( $0.45)    ($17.78)   ($4.26)
Extraordinary Item Income Per Share -
  Basic and Diluted                                  -          -           -     $0.47
Net Loss Per Share -
  Basic and Diluted                             ($9.50)    ($0.45)    ($17.78)   ($3.79)

</Table>

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


                                        3


<Page>
<Table>
<Caption>

                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                             (Dollars in thousands)


                                                 September 30,        December 31,
                                                      2005                2004
                                                  ____________        ____________
<S>                                                   <C>                 <C>
ASSETS

Current Assets:
  Cash & Cash Equivalents                           $2,360              $9,627
  Accounts Receivable, net                           2,479                 639
  Prepayments & Other Assets                           116                  83
                                                   _______             _______
      Total Current Assets                           4,955              10,349

Other Long Term Assets:
  Gas and Oil Properties, net                       23,086                 670
  Property, Plant and Equipment, net                  ,280                   0
  Restricted Cash - Escrow                             936               2,500
  Intangible Asset                                      45                  45
  Other Long Term Assets                               527                 518
                                                   _______             _______
      Total Other Assets                            28,874               3,733

TOTAL ASSETS                                       $33,829             $14,082
                                                   =======             =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
  Accounts Payable and Accrued Expenses             $1,085                $769
  Accrued Taxes                                         56                  92
  Notes Payable                                     20,873                   0
  Other Current Liabilities                            202                 741
                                                   _______             _______
          Total Current Liabilities                 22,216               1,602

Deferred Gain on Energy Contract                     1,337               1,534
Unrealized Loss on Energy Contract -
  at market                                         12,499               3,424
Long Term Liability                                  2,479               2,479

Minority Interest in Subsidiary                        276                 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                              16,253              26,293
                                                   _______             _______
          Total Stockholders' Equity                (4,978)              4,824
                                                   _______             _______

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY         $33,829             $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)

                                                                    Nine Months Ended
                                                                      September 30,
                                                                    2005          2004
                                                                    ____          ____
<S>                                                             <C>           <C>
Net cash flow from operating activities:
    Net loss                                                      ($10,040)     ($2,253)
    Adjustments to reconcile net loss to net
    cash provided by (used in) operating activities:
         Minority interest                                              58           16
         Extraordinary gain, net of tax                                  0         (278)
         Unrealized loss on the mark-to-market of energy
          Contract                                                   9,076        3,198
         Amortization of deferred gain on energy contract             (198)        (198)
         Non-cash compensation expense                                  57          129
         Depreciation, depletion and amortization                    1,220            0
         (Increase) decrease in accounts receivable                 (1,840)           3
         (Increase) decrease in prepaids and other assets             (478)       1,950
         Increase (decrease)in accounts payable and accrued
          expenses                                                     318         (256)
         Increase (decrease) in taxes accrued                          (36)          19
         Increase in miscellaneous and other liabilities                84        1,995
                                                                  ________      _______
      Net cash provided by (used in) operating activities           (1,779)       4,325

Net cash provided by (used in) investing activities:
          Investment in hydro plants and property                   (2,339)           0
          Investment in oil and gas properties                     (23,577)           0
          Investment in HoustonStreet                                   (2)           0
          Consolidation of HoustonStreet                                 0          393
                                                                  ________      _______
      Net cash provided by (used in) investing activities          (25,918)         393

Net cash provided by (used in) financing activities:
         Stock option exercise                                         180           41
         Proceeds from convertible notes                            20,250            0
         Reacquired capital stock and options                            0       (1,156)
                                                                  ________      _______
      Net cash provided by (used in) financing activities           20,430       (1,115)

Net increase (decrease) in cash and cash equivalents                (7,267)       3,603
Cash and cash equivalents, beginning of period                       9,627        7,469
                                                                  ________      _______
Cash and cash equivalents, end of period                            $2,360      $11,072
                                                                  ========      =======
Supplemental disclosure of cash flow information:
  Cash paid during the period for income taxes                      $   45      $    15
                                                                  ________      ________

</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  September 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
September 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 BayCorp can make investments.

  In  September 2003, BayCorp formed Great Bay Hydro  Corporation
("Great  Bay  Hydro"), a New Hampshire corporation, as  a  wholly
owned  subsidiary.  Great Bay Hydro entered into a  purchase  and
sale  agreement,  dated  as of October 30,  2003,  with  Citizens
Communications  Company  ("Citizens") to acquire  the  generating
facilities  in Vermont owned by the Vermont Electric Division  of
Citizens.  Great Bay Hydro completed the acquisition and  assumed
operating responsibility of the generating facilities on April 1,
2004.    The   generating   facilities   include   an   operating
hydroelectric  facility of approximately 4 megawatts  located  in
Newport, Vermont, diesel engine generators totaling approximately
7   megawatts  located  in  Newport,  Vermont  and  non-operating
hydroelectric facilities in Troy and West Charleston, Vermont.

  In   October  2004,  BayCorp  formed  Nacogdoches  Power,   LLC
("Nacogdoches Power"), a New Hampshire limited liability company,
as  a wholly owned subsidiary.  On November 16, 2004, Nacogdoches
Power acquired the development rights to an approximately 1000 MW
natural  gas-fired  power plant project  in  Nacogdoches  County,
Texas,  located in east Texas (the "Sterne Power Project").   The
project  received its air quality permit in December 2002,  which
is  effective through December 7, 2005.  Nacogdoches Power has  a
wastewater  discharge permit that is currently effective  through
August  1,  2006.  Nacogdoches Power has options to  acquire  the
land and a number of easements for the Sterne Power Project.  The
proposed  plant  site  is located near the  Electric  Reliability
Council  of  Texas ("ERCOT") and the Southwest  Power  Pool  high
voltage  transmission lines as well as a source of cooling  water
and  natural  gas  lines.   Nacogdoches  Power  is  pursuing  the
development of this project using a fuel other than natural gas.

  As part of its efforts to secure a natural gas supply for the
Sterne Power project, BayCorp determined that significant natural
gas and oil exploration and production activities were being
carried out in Nacogdoches County, Texas near the location of the


                                6

<Page>

Sterne  Power project.  It was through this process that  BayCorp
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
fund the total cost of the new wells, with the provision that  up
to  25%  of the cost may be funded and acquired by other parties,
(the  "Funding Percentage") and will own a working interest equal
to  90%  of the Funding Percentage 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 eight  wells.   The
net revenue interest in each of these eight wells being funded by
Nacogdoches Gas is 77% with the remaining 23% of the net revenues
paid  to  the lessor and other royalty interests.  For the  first
four wells funded under the January 7, 2005 agreement Nacogdoches
Gas  had  a  100% Funding Percentage and acquired a  90%  working
interest.   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.  For the next four wells  funded  under
the January 7, 2005 agreement, Nacogdoches Gas had an 85% Funding
Percentage  and  acquired a 76.5% working interest.   This  means
that  Nacogdoches Gas bears 76.5% of the operating costs of these
four wells and receives 58.9% of the net revenues from the wells.

  The  first  of  the eight wells, Round Mountain, a  James  Lime
horizontal natural gas well, began production in January 2005 and
through the end of September 2005 has produced approximately  268
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  September  2005  has
produced  approximately 243 million cubic feet  of  natural  gas.
The  fourth well, Whirlwind, a James Lime horizontal natural  gas
well,  began  production  in May 2005  and  through  the  end  of
September 2005 has produced approximately 158 million cubic  feet
of natural gas.

  The  fifth well, Looking Glass, a James Lime horizontal natural
gas  well, began production in late July 2005 after the  fracture
stimulation of one of its four sections and through  the  end  of
September  2005 has produced approximately 38 million cubic  feet
of  natural  gas.  The sixth well, Thunder Chief,  a  James  Lime
horizontal natural gas well, began production in late August 2005
without  fracture  stimulation and through the end  of  September
2005  has produced approximately 30 million cubic feet of natural
gas.   The  seventh well, Night Spirit, a horizontal  James  Lime
natural  gas  well,  began  production in  early  September  2005
without  fracture  stimulation and through the end  of  September
2005  has produced approximately 74 million cubic feet of natural
gas.   The  eighth  well,  Wind Dancer, a horizontal  James  Lime
natural Gas well, began production in late September 2005 without
fracture  stimulation and through the end of September  2005  has
produced  approximately 17 million cubic  feet  of  natural  gas.
Each  of  these  wells  requires fracture stimulation,  which  if
successful,  would  allow  the  well  to  be  placed  into   full
production.   The  schedule and timing  for  performing  fracture
stimulation  of these wells is uncertain given the strong  demand
for these services in the industry.


                                7

  <Page>

  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
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  has  a 90% interest and Sonerra has 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%.  BayCorp 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 ("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.  BayCorp  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  October  2005  through  December 2005  (based  on  projected
monthly  generation) is approximately $52.40  per  megawatt  hour
("MWh".)   The results of operations of Benton Falls are included
in BayCorp's financial statements from 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.


                                8

  <Page>

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 - SLOAN ACQUISITION CORP. TENDER OFFER

  On  October  12,  2005,  Sloan Acquisition  Corp.,  a  Delaware
corporation  (the "Purchaser") and a wholly owned  subsidiary  of
Sloan  Group  Ltd., a Bahamas international business  corporation
("Sloan  Group"),  disclosed  in  a  Tender  Offer  Statement  on
Schedule  TO ("Schedule TO"), its offer to purchase  all  of  the
issued and outstanding shares of the Company's common stock at  a
price of $14.19 per share, net to the seller in cash, (the "Offer
Price") upon the terms and subject to the conditions set forth in
the Offer to Purchase (the "Offer to Purchase") dated October 12,
2005,  and in the related Letter of Transmittal (which,  together
with the Offer to Purchase, constitute the "Offer").

  The  Offer  was  made  pursuant to  the  Amended  and  Restated
Agreement and Plan of Merger, dated as of September 30, 2005,  by
and among Sloan Group, the Purchaser and the Company (the "Merger
Agreement").  The Merger Agreement provides that as  promptly  as
practicable  after  the purchase of the shares  pursuant  to  the
Offer  and  the  satisfaction or, if permissible, waiver  of  the
other  conditions  set  forth in the Merger Agreement,  Purchaser
will  be merged with and into the Company (the "Merger").   As  a
result  of the Merger, the Company will continue as the surviving
corporation  (the "Surviving Corporation") and will be  a  wholly
owned  subsidiary of Sloan Group.  At the effective time  of  the
Merger,  each  share  of the Company's common  stock  issued  and
outstanding  immediately prior to the Effective Time (other  than
Common Stock held in the treasury of the Company or by Purchaser,
Sloan  Group or any direct or indirect subsidiary of Sloan  Group
or  the Company, and other than Common Stock held by stockholders
who  shall  have  demanded and perfected appraisal  rights  under
Delaware Law)  will be canceled and converted automatically  into
the right to receive $14.19 in cash.

  The  Offer, as extended, expired at 12:00 midnight Eastern time
on  Thursday, November 10, 2005.  Parent and Purchaser have  been
advised  by SunTrust Bank, which is serving as the Depositary  in
connection  with  the  Offer, that as of the  expiration  of  the
Offer,  a  total of 499,310 shares were tendered  in  the  offer,
including 1,036 shares covered by notices of guaranteed delivery.
All  such shares were accepted for payment in accordance with the
terms  of  the  Offer.  The tendered shares,  together  with  the
25,000  shares  that had already been held by  Sloan  Acquisition
Corp.  and its affiliates, represent approximately 91.7%  of  the
outstanding common stock of the Company.

NOTE C - 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") with Sloan Group Ltd., a Bahamas corporation  (the
"Sloan  Group").  On May 24, 2005, the Company, and  all  of  its
wholly  owned subsidiaries, entered into a $10,000,000  multiple-
draw  senior  convertible note (the "Second Note",  and  together
with  the  First Note, the "Convertible Notes") with Sloan  Group
and  as of September 30, 2005, had drawn $10,000,000 against  the
Second  Note.  The total debt under the Convertible Notes,  which
accrues  interest at 8% per annum and is due and payable in  full
on  December 15, 2005, is convertible by 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 Convertible Notes) into shares of  the
Company's  common  stock  at a price of  $14.04  per  share.   At
December  15,  2005,  the  end  of  the  conversion  period,  the
principal  and  interest  of  the  Convertible  Notes  would   be
convertible into approximately 1,510,889 shares, which would


                                9

<Page>

represent  approximately 66% of the Company's common stock  on  a
fully  diluted  basis  (based  on 770,483  currently  outstanding
shares  and  options.) The Convertible Notes  do  not  allow  the
Company  to  prepay the debt (or pay any interest in cash  unless
Sloan Group elects to permit such payment), and provides for a 2%
premium  on the interest rate in the event of a default.  Payment
of  the  Convertible Notes may be accelerated in the event  of  a
material event of default.  The proceeds of the Convertible Notes
were  used  to  fund the Company's acquisition  of  hydroelectric
generating facilities in Maine and its investment in certain  oil
and gas exploration opportunities.

  In  addition to the Convertible Notes, on October 7, 2005,  the
Company and all of its wholly owned subsidiaries entered  into  a
$7,750,000  multiple-draw senior secured note (the "Third  Note",
and together with the Convertible Notes, the "Notes").  Any draws
under the Third Note accrue interest at 8% per annum, are due  on
April  1,  2006 and may be prepaid at any time, but  may  not  be
reborrowed  once repaid.  The Third Note is not convertible  into
the  Company's  stock.  As of October 30, 2005, the  Company  had
drawn  approximately $2.8 million against the  Third  Note.   The
Company  has  drawn and intends to draw upon the  Third  Note  to
continue  the  development of natural gas and oil wells  in  East
Texas  under  its  Project  Development  Agreement  with  Sonerra
Resources  Corporation  and  for  other  strategic  and   general
corporate purposes.

  In  addition  to  the Company, the borrowers  under  the  Notes
include the following subsidiaries of the Company: GBH Maine, GBH
Benton,  Great  Bay  Power Marketing, Great  Bay  Hydro,  BayCorp
Ventures,  Nacogdoches  Power, and Nacogdoches  Gas.   Under  the
Second Amended and Restated Pledge Agreement entered into at  the
time  of  the  Third  Note, the Company has  pledged  its  equity
interests  in HoustonStreet, GBH Maine and Nacogdoches  Gas;  GBH
Maine  has pledged its equity interests in GBH Benton and  Benton
Falls;  and GBH Benton has pledged its equity interests in Benton
Falls.   Nacogdoches Gas, GBH Maine and GBH Benton  have  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.  The  Notes  are  all
secured by the same collateral and a default under one loan would
be a default under all of the loans.

NOTE D - 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.


                               10

<Page>

  Principles of Consolidation

  The  Company's  Consolidated Financial Statements  include  the
accounts  of  the Company and all its subsidiaries.  In  November
2004,  the  Company  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.

  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  the
Company  held a minority interest in HoustonStreet, it  accounted
for HoustonStreet under the equity method.  A recapitalization of
HoustonStreet  was  completed effective May 1,  2004,  and  as  a
result,   the   Company's  ownership  interest  in  HoustonStreet
increased  above 50%.  As a result of this recapitalization,  The
Company began consolidating HoustonStreet as of May 1, 2004.

  Energy Marketing

  Forward contracts, including the purchased power contract  with
Unitil  dated  as of April 1, 1993 (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 nine months ended September 30, 2005 and $129,000
in  the  nine months ended September 30, 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  nine  months  ended September 30, 2005 or  during  the  nine
months ended September 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.


                               11

<Page>


  Asset Retirement Obligation

  The  Company  has  adopted  the  provisions  of  Statement   of
Financial  Accounting  Standards No. 143, "Accounting  for  Asset
Retirement Obligations" ("SFAS 143").  SFAS 143 requires entities
to  record  the fair value of a liability for an asset retirement
obligation  in the period in which it is incurred if a reasonable
estimate of fair value can be made, and the corresponding cost is
capitalized  as part of the carrying amount of the related  long-
lived asset.  The liability is accreted to its present value each
period,  and the capitalized cost is depreciated over the  useful
life  of the related asset.  If the liability is settled  for  an
amount  other  than  the  recorded amount,  a  gain  or  loss  is
recognized.    The  Company  has  asset  retirement   obligations
associated  with  the future plugging and abandonment  of  proved
properties  and related facilities.  The estimated  liability  is
based  upon  historical  experience in  plugging  and  abandoning
wells, estimated remaining lives of those wells, estimates as  to
the cost to plug and abandon the wells in the future, and federal
and  state  regulatory requirements.  The liability is discounted
using   an  assumed  credit-adjusted  risk-free  interest   rate.
Revisions  to  the  liability  could  occur  due  to  changes  in
estimates of plugging and abandonment costs, changes in the risk-
free interest rate or remaining lives of the wells, or if federal
or   state   regulators  enact  new  plugging   and   abandonment
requirements.

NOTE E - COMMITMENTS AND CONTINGENCIES

Purchased Power Agreements

  Great  Bay was party to a purchased power contract, the  Unitil
PPA, 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 had an option, which expired November 1, 2005, to extend
the  Unitil PPA for up to 12 years, until 2022.  Unitil  did  not
exercise this option.

  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


                               12

<Page>

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 $12.5 million as of September  30,  2005
and  was  negative  $3.4 million as of December  31,  2004.   The
deferred  gain on the contract was $1.3 million as  of  September
30, 2005 and $1.5 million as of December 31, 2004.  These amounts
are reflected in the Company's balance sheet.

  On  March 17, 2003, Unitil announced the approval of a contract
with  Mirant  Americas  Energy Marketing,  LP  ("Mirant"),  which
provided   for  the  sale  of  Unitil's  existing  power   supply
entitlements,  including the PPA with Great Bay Power  Marketing,
effective on May 1, 2003.  Great Bay Power Marketing's  PPA  with
Unitil  has  not  been assigned to Mirant.   Rather,  Unitil  has
appointed Mirant as their agent for purposes of administering the
PPA  with  Great  Bay  Power Marketing and Mirant  is  purchasing
Unitil's entitlement under the PPA.

NOTE F - OIL AND GAS ACTIVITIES

  The  following summarizes selected information with respect  to
oil and gas producing activities.

                                       September  30, 2005
                                       ___________________
                                         (in thousands)
       Gas and Oil properties:
       Land                                  $ 2,299
       Properties subject to depletion        18,478
       Unproved properties                     3,489
                                             _______
         Total                                24,266
       Accumulated depletion                   1,180
                                             _______
         Net                                 $23,086
                                             =======

  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.


                               13

<Page>

  Production  quantities  shown are net  volumes  withdrawn  from
reservoirs.   These  may  differ from  sales  quantities  due  to
inventory  changes, and especially in the case  of  natural  gas,
volumes  consumed  for fuel and/or shrinkage from  extraction  of
natural gas liquids.
  Quantities of Proved Natural Gas Reserves (Mmcf):

   Balance December 31, 2004                       149
     Revisions                                       0
     Extensions, discoveries and additions           0
     Purchases                                  11,311
     Sales                                           0
     Production                                   (606)
                                                _______
   Balance, September 30, 2005                  10,854

NOTE G - INVESTMENT IN HOUSTONSTREET

  A recapitalization at HoustonStreet was completed in the second
quarter  of  2004  and  as  a result,  the  Company  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  the
Company'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, the Company held  a  minority
ownership   interest   in   HoustonStreet   and   accounted   for
HoustonStreet  under  the  equity  method.   The  Company  ceased
recording  losses in HoustonStreet during 2001 when the  carrying
value  of  its  investment  (including  all  advances  and  notes
payable)  was reduced to zero.  The Company has no obligation  to
fund  and  does  not  guarantee any  outstanding  obligations  of
HoustonStreet.  The Company has not recorded any portion  of  its
share  of  HoustonStreet's earnings during  2004  (preceding  the
consolidation  of  HoustonStreet), 2003 or 2002  since  any  such
earnings  were  fully  offset  by  suspended  losses.  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 H - EQUITY

  As  of September 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.



                               14

<Page>

NOTE I - SEGMENT INFORMATION

  BayCorp  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.  BayCorp 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>

                                                     Crude
                                                    Oil and
 BayCorp Holdings, Ltd.                             Refined
 As of and for the nine                             Product
      months ended        Electricity    Oil and       s               Inter-
      September 30        Generation       Gas      Trading            company
        ($000's)          and Trading  Production   Exchang   Other     Elim      Total
                                                       e
                                                      (1)
________________________________________________________________________________________

<S>                        <C>          <C>          <C>     <C>      <C>        <C>
2005
____
Revenues                   $4,469       $4,713       $750        $0        $0     $9,932
Operating Expenses         13,709        3,870        613     1,585         0     19,777
Segment Net Income (Loss)  (9,715)         599        145      (924)     (145)   (10,040)
Total Assets               12,397       25,050        717    38,098   (42,433)    33,829
________________________________________________________________________________________

2004
____
Revenues                   $3,521            -       $398      $0       $0        $3,919
Operating Expenses          6,500            -        361     1,027      (211)     7,677
Segment Net Income (Loss)  (2,955)           -         24       702     (24)       2,253
Total Assets                9,280            -        537    19,023   (14,159)    14,681
________________________________________________________________________________________


</Table>

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



                               15

  <Page>

NOTE J - 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 has 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

  The Company derived its revenues primarily through energy sales
activities by Great Bay Power Marketing, Great Bay Hydro,  Benton
Falls  and Nacogdoches Gas in the first nine months of 2005.   In
the  first nine months of 2004, the Company derived its  revenues
from  nine months of operation at Great Bay Power Marketing,  six
months  of  operation  at  Great Bay Hydro  and  five  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  hydroelectric facilities in Troy and West  Charleston,
Vermont.  Great Bay Hydro assumed operating responsibility of the
generating facilities


                               16

<Page<

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, 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 Resources Corp ("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
fund the total cost of the new wells, with the provision that  up
to  25%  of the cost may be funded and acquired by other  parties
and  will  own  a  working interest equal to 90% of  the  Funding
Percentage  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 eight  wells.   The
net revenue interest in each of these eight wells being funded by
Nacogdoches Gas is 77% with the remaining 23% of the net revenues
paid  to  the lessor and other royalty interests.  For the  first
four wells funded under the January 7, 2005 agreement Nacogdoches
Gas  had  a  100% Funding Percentage and acquired a  90%  working
interest.   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.  For the next four wells  funded  under
the January 7, 2005 agreement, Nacogdoches Gas had an 85% Funding
Percentage  and  acquired a 76.5% working interest.   This  means
that  Nacogdoches Gas bears 76.5% of the operating costs of these
four wells and receives 58.9% of the net revenues from the wells.

  The  first  of  the eight wells, Round Mountain, a  James  Lime
horizontal natural gas well, began production in January 2005 and
through the end of September 2005 has produced approximately  268
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  September  2005  has
produced  approximately 243 million cubic feet  of  natural  gas.
The  fourth well, Whirlwind, a James Lime horizontal natural  gas
well,  began  production  in May 2005  and  through  the  end  of
September 2005 has produced approximately 158 million cubic  feet
of natural gas.

  The  fifth well, Looking Glass, a James Lime horizontal natural
gas  well, began production in late July 2005 after the  fracture
stimulation of one of its four sections and through  the  end  of
September  2005 has produced approximately 38 million cubic  feet
of  natural  gas.  The sixth well, Thunder Chief,  a  James  Lime
horizontal natural gas well, began production in late August 2005
without  fracture  stimulation and through the end  of  September
2005


                               17

<Page>

has  produced approximately 30 million cubic feet of natural gas.
The  seventh well, Night Spirit, a horizontal James Lime  natural
gas  well,  began  production  in early  September  2005  without
fracture  stimulation and through the end of September  2005  has
produced approximately 74 million cubic feet of natural gas.  The
eighth  well,  Wind Dancer, a horizontal James Lime  natural  Gas
well,  began  production in late September 2005 without  fracture
stimulation  and through the end of September 2005  has  produced
approximately  17  million cubic feet of natural  gas.   Each  of
these  wells  requires fracture stimulation, which if successful,
would  allow  the  well to be placed into full  production.   The
schedule and timing for performing fracture stimulation of  these
wells is uncertain given the strong demand for these services  in
the industry.

  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 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 has a 90%  interest  and
Sonerra has 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.

  Expenses  for the first nine 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,  the  Company  began   consolidating
HoustonStreet  for financial reporting purposes and HoustonStreet
revenues  and expenses are reflected in the Company's  financials
as  of  that date.  See "Item 1. Financial Statements. Note  G  -
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: Third Quarter of 2005 Compared to the
Third Quarter of 2004

Operating Revenues

  BayCorp's   operating  revenues  increased   by   approximately
$2,656,000 to $4,098,000 in the third quarter of 2005 as compared
to  $1,442,000 in the third quarter of 2004.  Total revenues  for
the  third  quarter  of  2005 included  approximately  $1,007,000
generated from Great Bay Power Marketing's long-term power  sales
contract  with  Unitil and approximately $3,000 in  net  revenues
from   Great  Bay  Power  Marketing's  energy  commodity  trading
activity.  The gross


                               18

<Page>

retail  sales  volume  of energy commodity trading  activity  was
approximately  $341,000  and  the  related  cost  of  sales   was
approximately  $338,000.  In addition, in the  third  quarter  of
2005,   Great  Bay  Hydro  generated  revenues  of  approximately
$397,000  and  Benton Falls generated revenues  of  approximately
$68,000  from the sale of electricity.  Nacogdoches Gas generated
revenues of approximately $2,385,000 from the sale of natural gas
and  HoustonStreet generated revenues of approximately  $238,000.
Operating  revenues in the third quarter of 2004  included  Great
Bay  Power Marketing revenues of approximately $1,003,000,  Great
Bay  Hydro  revenues of approximately $196,000 and  HoustonStreet
revenues of approximately $242,000.

  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 third quarters of both 2005 and 2004.   The
cost of power purchased to supply this contract was approximately
8.50   cents  per  kWh  for  the  third  quarter  of   2005   and
approximately 4.48 cents per kWh for the third quarter  of  2004.
For  the  third quarter of 2005, the Company realized an  average
selling  price for electricity generated and sold  by  Great  Bay
Hydro of approximately 8.61 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 $803,000, or 89.5%, to $1,700,000  in
the  third  quarter of 2005 as compared to $897,000 in the  third
quarter of 2004.

  The  Company recorded a non-cash charge for an unrealized  loss
on  the mark-to-market of its long term energy sales contract and
recorded the amortization of the deferred inception gain on  this
contract  for  a  total  net  unrealized  loss  of  approximately
$5,490,000  in  the third quarter of 2005 as compared  to  a  net
unrealized loss of approximately $648,000 in the third 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  third
quarter of 2004 and have continued to rise into the third 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 increased  approximately
$246,000 to $268,000 in the third quarter of 2005 as compared  to
approximately  $22,000  in  the  third  quarter  of  2004.   This
increase was primarily due to increased operations at Nacogdoches
Gas, Great Bay Hydro and Benton Falls.

  Administrative  and  general expenses  increased  approximately
$608,000  to $1,128,000 in the third quarter of 2005 as  compared
to  $520,000  in  the third quarter of 2004.   This  increase  in
administrative and general expenses was primarily attributable to
the  cost of legal and professional services associated with  the
tender  offer by Sloan Acquisition Corp. in the third quarter  of
2005.   See  "Item  1.  Financial  Statements.  Note  B  -  Sloan
Acquisition  Corp.  Tender  Offer."  The  Company  also  incurred
administrative and general expenses associated with the Company's
operations at Nacogdoches Gas, Nacogdoches Power and Benton Falls
in  the third quarter of 2005.  There were no administrative  and
general  expenses associated with these companies  in  the  third
quarter of 2004.

                               19

<Page>

  Depreciation,  depletion  and  amortization  was  approximately
$521,000  in the third quarter of 2005 and reflects approximately
$491,000   in   depletion  expense  of  Nacogdoches   Gas   lease
acquisition costs and development costs for the third 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  third  quarter  of  2005.   There  were   no
depletion,  depreciation or amortization expenses  in  the  third
quarter of 2004.

  Taxes  other  than  income decreased approximately  $10,000  to
$50,000  in  the third quarter of 2005 as compared to $60,000  in
the third quarter of 2004 primarily due to accruals for Great Bay
Hydro and Benton Falls property taxes.

  The Company recorded other deductions of approximately $347,000
in the third quarter of 2005 as compared to other income of
approximately $440,000 in the third quarter of 2004.  Included in
other deductions in the third quarter of 2005 was approximately
$362,000 in interest expense associated with the debt financing
provided by Sloan Group.  See "Item 1. Financial Statements. Note
C - Debt Financing."  Other income in the third quarter of 2004
primarily reflected closing adjustments and other costs specific
to the Company's sale of its interests in Seabrook.  In the third
quarter of 2004, the Company negotiated a final settlement of the
remaining accrued liability related to the sale of Seabrook and
paid approximately $168,000 in settlement of this liability.  As
a result of this liability being settled for less than the
Company had previously estimated and accrued for, the Company
recorded other income of approximately $634,000 in the third
quarter of 2004.  Also in the third quarter of 2004, the Company
recorded other income of approximately $75,000 upon receipt of an
insurance refund related to its ownership in Seabrook.
Offsetting these income items in the third quarter of 2004, the
Company recorded an expense of $255,000 for a directors and
officers liability insurance policy; this run-off policy insures
against claims, including nuclear related claims, for events that
may have occurred prior to July 2004.

Net Loss

  As  a  result  of the above factors, for the third  quarter  of
2005,   the   Company  recorded  a  net  loss  of   approximately
$5,427,000,  or $9.50 per share, as compared to  a  net  loss  of
approximately $250,000, or $0.45 per share, for the third quarter
of 2004.

Results of Operations: First Nine Months of 2005 Compared to the
First Nine Months of 2004

Operating Revenues

  BayCorp's   operating  revenues  increased   by   approximately
$6,013,000  to  $9,932,000 in the first nine months  of  2005  as
compared  to $3,919,000 in the first nine months of 2004.   Total
revenues for the first nine months of 2005 included approximately
$4,713,000  from  the  sale of natural gas  by  Nacogdoches  Gas.
Great   Bay   Power  Marketing  had  revenues  of   approximately
$2,988,000  from its long-term power sales contract  with  Unitil
and  approximately  $45,000  in  net  revenues  from  its  energy
commodity  trading activity.  The gross retail  sales  volume  of
energy  commodity  trading activity was approximately  $1,437,000
and  the related cost of sales was approximately $1,392,000.   In
addition,  in  the  first nine months of 2005,  Great  Bay  Hydro
generated  revenues of approximately $929,000, and  Benton  Falls
generated  revenues of approximately $507,000 from  the  sale  of
electricity.  HoustonStreet generated revenues  of  approximately
$751,000.   Consolidated operating revenues  in  the  first  nine
months of 2004 were approximately $3,041,000 from Great Bay Power
Marketing,  $479,000  from  Great Bay  Hydro  and  $398,000  from
HoustonStreet.


                               20

<Page>

  The  Company  realized an average selling price for electricity
sold under the Unitil sales contract of 5.03 cents per kWh in the
first nine months of both 2005 and 2004.  The cost of power
purchased  to supply this contract was approximately  6.83  cents
per  kWh for the first nine months of 2005 and approximately 5.08
cents  per  kWh for the first nine months of 2004.   The  Company
realized  an average selling price for electricity generated  and
sold  by Great Bay Hydro of approximately 6.21 cents per kWh  and
4.92  cents per kWh for the nine months ended September 30,  2005
and  2004, respectively, and Great Bay Hydro's cost of generating
power was approximately 4.19 cents per kWh and 3.01 cents per kWh
for   the  nine  months  ended  September  30,  2005  and   2004,
respectively.   For  the first nine months of 2005,  the  Company
realized  an average selling price for electricity generated  and
sold  by  Benton Falls of approximately 5.70 cents  per  kWh  and
Benton  Fall's  cost  of generating power was approximately  3.50
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 $1,025,000, or 33.9%, to $4,051,000 in
the  first nine months of 2005 as compared to $3,026,000  in  the
first nine months of 2004.

  The  Company recorded a non-cash charge for an unrealized  loss
on  the mark-to-market of its long term energy sales contract and
recorded the amortization of the deferred inception gain on  this
contract  for  a  total  net  unrealized  loss  of  approximately
$8,878,000 in the first nine months of 2005 as compared to a  net
unrealized  loss of approximately $3,000,000 in  the  first  nine
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  nine  months of 2004 and have continued to rise  into  the
first  nine  months  of 2005 primarily due to  increases  in  the
forward price of natural gas.

  Production   and   transmission  expenses  were   approximately
$2,796,000  in  the  first nine months of  2005  as  compared  to
approximately  $44,000  in  the  first  nine  months   of   2004.
Production  expenses associated with Nacogdoches  Gas  operations
were  approximately $2,641,000 in the first nine 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 nine  months  of
2004 were specific to Great Bay Hydro operations.

  Administrative  and  general expenses  increased  approximately
$1,128,000, or 73.6%, to $2,660,000 in the first nine  months  of
2005  as compared to $1,532,000 in the first nine 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  in  the
first  nine  months  of 2005.  There were no  administrative  and
general  expenses associated with Nacogdoches Gas and Nacogdoches
Power in the first nine months of 2004.  In the first nine months
of  2005  the  Company also incurred administrative  and  general
expenses  of  approximately $408,000 for legal  and  professional
services  associated with the tender offer by  Sloan  Acquisition
Corp.  in  the  third  quarter of 2005.  See "Item  1.  Financial
Statements. Note B -Sloan Acquisition Corp. Tender Offer."

  Depreciation,   depletion   and   amortization   expense    was
approximately  $1,220,000 in the first nine months  of  2005  and
reflected  approximately $1,161,000 in depletion  of  Nacogdoches
Gas  lease acquisition costs and development costs for the  first
nine  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 $60,000 for depreciation of plant and equipment  at
the  Company's hydro facilities in the first nine months of 2005.
There  was no depletion, depreciation or amortization expense  in
the first nine months of 2004.


                               21

<Page>

  Taxes  other  than income increased approximately  $74,000,  to
$171,000 in the first nine months of 2005 as compared to  $97,000
in the first nine months of 2004 primarily due to Great Bay Hydro
and Benton Falls property taxes.

  The Company recorded other deductions of approximately $426,000
in  the first nine months of 2005 as compared to other income  of
approximately  $1,110,000  in the  first  nine  months  of  2004.
Included in other deductions in the first nine months of 2005 was
approximately  $623,000 in interest expense associated  with  the
debt  financing provided by Sloan Group.  See "Item 1.  Financial
Statements.  Note C - Debt Financing."  Offsetting  this  expense
was  other  income  of approximately $144,000 from  an  insurance
refund  related to the Company's previous ownership  in  Seabrook
and an accrual adjustment of approximately $92,000.  Other income
in  the first nine months of 2004 primarily reflected receipt  by
the  Company  of one-time payments and other closing  adjustments
specific  to  the Company's sale of its interests in Seabrook  in
November 2002.

  Income  tax  income in the first nine 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.

  In  the  first  nine 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 nine months of
2005,   the   Company  recorded  a  net  loss  of   approximately
$10,040,000, or $17.78 per share, as compared to a  net  loss  of
approximately $2,253,000, or $3.79 per share, for the first  nine
months of 2004.

Liquidity and Capital Resources

  As  of September 30, 2005, BayCorp had approximately $2,360,000
in  cash  and  cash equivalents and 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 $527,000 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 Third Note with  Sloan
Group,  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  with
Sloan Group (the "First Note").  On May 24, 2005, the Company and
all  of  its wholly owned subsidiaries entered into a $10,000,000
multiple-draw  convertible note with  Sloan  Group  (the  "Second
Note" and, together with the First Note, the "Convertible Notes")
and, as of September 30, 2005, had drawn $10 million against this
debt  facility.    The  total debt under the  Convertible  Notes,
which accrues interest at 8% and is due on December 15, 2005, is


                               22

<Page>

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 the Convertible  Notes,  on
October  7,  2005,  the  Company and  all  of  its  wholly  owned
subsidiaries  entered  into  a  $7,750,000  multiple-draw  senior
secured  note  with Sloan Group (the "Third Note"  and,  together
with  the  Convertible Notes, the "Notes").  Any draws under  the
Third  Note accrue interest at 8% per annum and are due on  April
1,  2006.   As  of  October  30,  2005,  the  Company  had  drawn
approximately $2.8 million against the Third Note.   All  of  the
Company's borrowings from Sloan Group are secured under a  Second
Amended  and  Restated Pledge Agreement and cross-collateralized,
and a default under any one of the Notes would be a default under
all   of  the  Notes.   The  Company  used  proceeds  from  these
financings  to  finance the acquisition of Benton  Falls  by  GBH
Maine  and GBH Benton, 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.  See "Item 1. Financial Statements. Note C  -
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 nine months of 2005  of
approximately  $10,040,000.  There was a non-cash charge  for  an
unrealized  loss  on  the mark-to-market of  the  Unitil  PPA  of
approximately $9,076,000 and a non-cash recognition  of  deferred
gain  on the Unitil PPA of approximately $198,000.  The value  of
this  contract  is based on current projections of  power  prices
over  the  life of the contract.  Forward power prices  increased
during  the first nine 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  $58,000  for HoustonStreet minority  interest  and
approximately   $1,220,000   for  depreciation,   depletion   and
amortization.

  An  increase in accounts receivable in the first nine months of
2005  of  approximately $1,840,000 was primarily attributable  to
accounts   receivable  at  Nacogdoches  Gas.   An   increase   of
approximately $478,000 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  $366,000  was
primarily attributable to an increase in accounts payable  as  of
September 30, 2005.

  Cash flows from investing activities included cash expenditures
of  approximately  $2,339,000 for fixed assets  as  part  of  the
Benton  Falls  purchase  and ongoing operations.   See  "Item  1.
Financial   Statements.  Note  A  -  The  Company."     Investing
activities  in  the  first  nine months  of  2005  also  included
investments  by Nacogdoches Gas of approximately $23,577,000  for
interests  in  eight  oil and natural gas wells.   See  "Item  1.
Financial Statements. Note A -The Company."

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

  Following  the sale of Seabrook in the fourth quarter  of  2002
and  the  completion of the Company's self 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


                               23

<Page>

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.

  Beginning in the first quarter of 2005, the Company has engaged
in  development of natural gas wells through Nacogdoches Gas, and
through September 2005, developed eight 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.

  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%.

  The  Company  intends to pursue investments that  will  require
additional  financing.  The Company believes that such  financing
is available, but there can be no assurance that


                               24

<Page>

the  Company  would be successful in obtaining such financing  or
obtaining  it  on  acceptable  terms.   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 Third Note with  Sloan
Group,  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 "Item 1. Financial Statements. Note  D  -
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.  Such statements include those regarding reserves  of
oil and gas and recovery by Nacogdoches Gas of its investment and
operating costs; the estimated purchased power rate under the CMP
PPA;  the  Merger  of  the Company with Sloan  Acquisition  Corp.
pursuant  to  the  September  30,  2005  Merger  Agreement;   the
Company's  efforts  to  acquire energy-related  assets;  and  the
financing  of  such  acquisitions,  additional  investments,  and
repayment  of the Notes. There are a number of important  factors
that  could  cause the results of BayCorp and/or its subsidiaries
to differ materially from those indicated by such forward-looking
statements.  These factors include, without limitation, those set
forth below and elsewhere in this report.

  Business  Opportunities  and  Development.   As  described   in
"Management's Discussion and Analysis of Financial Condition  and
Results  of  Operations - Liquidity and Capital  Resources,"  the
Company  has  evaluated  and  pursued  energy-related  investment
opportunities, has focused on the acquisition of 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.


                               25

<Page>

  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  September  30,  2005,  BayCorp   had
approximately   $5.3  million  in  cash  and  cash   equivalents,
restricted cash and short-term investments.  On March  15,  2005,
BayCorp and all of its wholly owned subsidiaries entered  into  a
$10,250,000 convertible note with Sloan Group (the "First Note").
On May 24, 2005, BayCorp and all of its wholly owned subsidiaries
entered  into a $10,000,000 multiple-draw convertible  note  with
Sloan Group (the "Second Note" and, together with the First Note,
the  "Convertible  Notes") and, as of September  30,  2005,   had
drawn  $10,000,000 against this debt facility.   The  total  debt
under  the  Convertible Notes, which accrues interest at  8%  per
annum and is due on December 15, 2005, is convertible at any time
between  November 15, 2005 and December 15, 2005 into  shares  of
BayCorp's  common  stock  at a price of  $14.04  per  share.   In
addition  to  the Convertible Notes, on October 7, 2005,  BayCorp
and  all  of  its  wholly  owned  subsidiaries  entered  into   a
$7,750,000  multiple-draw senior secured note  with  Sloan  Group
(the  "Third Note" and together with the Convertible  Notes,  the
"Notes").  Any draws under the Third Note accrue interest  at  8%
per  annum and are due on April 1, 2006.  As of October 30, 2005,
BayCorp  had drawn approximately $2.8 million against this  note.
All of BayCorp's borrowings from Sloan Group are secured under  a
Second   Amended  and  Restated  Pledge  Agreement   and   cross-
collateralized, and a default under any one of the Notes would be
a  default  under all of the Notes.  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.  See "Item 1. Financial  Statements.
Note C - 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  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 Third 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  seek
additional financing to meet ongoing cash requirements.  There is
no  assurance that the Company or its subsidiaries would be  able
to  raise  such capital or that the terms on which any additional
capital   is  available  would  be  acceptable.   Moreover,   the
Company's  need  to raise additional capital in order  to  pursue
certain   opportunities  may  affect  the  Company's  competitive
position with respect to such opportunities.  If additional funds
are  raised  by  issuing  equity  securities,  dilution  to  then
existing stockholders will result.

  Purchased  Power  Price  Risk.  The  price  of  electricity  is
subject  to  fluctuations resulting from changes  in  supply  and
demand.  The Company is party to a purchased power contract  with
Unitil  that provides for Great Bay Power Marketing  to  sell  to
Unitil  9.06  MWs  at $50.34 per MWh.  The Unitil  PPA  continues
through  October  31, 2010.  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


                               26

<Page>

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    Regulation   of   Natural   Gas.    The   interstate
transportation  and  certain sales for  resale  of  natural  gas,
including transportation rates charged and various other matters,
is subject to federal regulation by FERC.  Federal wellhead price
controls on all domestic gas were terminated on January 1,  1993,
so   gathering  systems  are  currently  not  subject   to   FERC
regulation.   The impact of future government regulation  on  any
natural  gas  facilities  cannot be predicted.   Although  FERC's
regulations should generally facilitate the transportation of gas
produced from producing properties and the direct access to  end-
user markets, the future impact of these regulations on marketing
production or on gas transportation business cannot be predicted.
BayCorp  and  its subsidiaries, however, should not  be  affected
differently than competing producers and marketers.

  Federal Regulation of Oil.  Sales of crude oil, condensate  and
natural  gas liquids are not currently regulated and are made  at
market  prices.  The net price received from the  sale  of  these
products is affected by market transportation costs.  Under rules
adopted  by FERC effective January 1995, interstate oil pipelines
can  change rates based on an inflation index, though other  rate
mechanisms may be used in specific circumstances.

  State  Regulation.   Oil  and  gas operations  are  subject  to
various types of regulation at the state and local levels.   Such
regulation includes requirements for drilling permits, the method
of  developing new fields, the spacing and operations  of  wells,
and  waste prevention.  The production rate may be regulated  and
the maximum daily production allowable from oil and gas wells may
be  established on a market demand or conservation  basis.  These
regulations may limit production by well and the number of  wells
that  can  be drilled.  To the extent that such gas is  produced,
transported and consumed wholly within one state, such operations
may,   in   certain  instances,  be  subject   to   the   state's
administrative authority charged with regulating pipelines.   The
rates that can be charged for gas, the transportation of gas, and
the construction and operation of such pipelines would be subject
to  the regulations governing such matters.  Certain states  have
recently  adopted regulations with respect to gathering  systems,
and  other  states are considering similar regulations.   Whether
new  regulations will be adopted or, if adopted, the effect these
rules may have on gathering systems cannot be predicted.

  Federal,  State  or  Native  American  Leases.   Operations  on
federal, state or Native American oil and gas leases are  subject
to  numerous restrictions, including nondiscrimination  statutes.
Such  operations  must be conducted pursuant to  certain  on-site
security regulations and other permits and authorizations  issued
by the Bureau of Land Management, Minerals Management Service and
other agencies.


                               27

<Page>

  Environmental  Regulations.  Various federal, state  and  local
laws  regulating the discharge of materials into the environment,
or  otherwise  relating  to the protection  of  the  environment,
directly   impact  oil  and  gas  exploration,  development   and
production operations, and consequently may impact operations and
costs.   These  laws and regulations govern, among other  things,
emissions to the atmosphere, discharges of pollutants into waters
of  the United States, underground injection of waste water,  the
generation,  storage,  transportation  and  disposal   of   waste
materials,  and  protection of public health, natural  resources,
and  wildlife.  These laws and regulations may impose substantial
liabilities for noncompliance and for any contamination resulting
from  operations and may require the suspension or  cessation  of
operations in affected areas.  To date, BayCorp has not  expended
any  material  amounts  to  comply  with  such  regulations,  and
management  does not currently anticipate that future  compliance
will  have  a materially adverse effect on BayCorp's consolidated
financial   position  or  results  of  operations.   BayCorp   is
committed to environmental protection and believes that it is  in
substantial  compliance  with applicable environmental  laws  and
regulations.   There are no known issues that have a  significant
adverse  effect  on  the permitting process or permit  compliance
status  of any of its facilities or operations.  BayCorp  expects
that  it  will  make  expenditures  in  efforts  to  comply  with
environmental  regulations  and requirements.   These  costs  are
considered a normal, recurring cost of ongoing operations and not
an extraordinary cost of compliance with government regulations.

  Risks   Related  to  HoustonStreet.   HoustonStreet's  revenues
depend  on continued and expanded use of Internet-based wholesale
energy trading platforms.  Electronic trading of wholesale energy
may  not  achieve widespread market acceptance  or  emerge  as  a
sustainable  business.  In addition, HoustonStreet will  need  to
enhance  trading  liquidity  in order  to  increase  and  sustain
revenues.   As  a  technology dependent business, HoustonStreet's
business  could suffer due to computer or communications  systems
interruptions  or  failures,  technological  change  or   adverse
competitive   developments.   Further,  as  electronic   commerce
evolves,   federal,  state  and  foreign  agencies  could   adopt
regulations  covering  issues such as user privacy,  content  and
taxation  of  products  and  services.   If  enacted,  government
regulations  could  materially adversely  affect  HoustonStreet's
business.  Although HoustonStreet currently is not aware that  it
infringes  any other patents, it is possible that HoustonStreet's
technology   infringes  patents  held  by  third   parties.    If
HoustonStreet  were  to be found infringing,  the  owner  of  the
patent could sue HoustonStreet for damages, prevent HoustonStreet
from making, selling or using the owner's patented technology  or
could  impose substantial royalty fees for those privileges.   If
any  of  the foregoing risks materialize, or other risks  develop
that adversely affect HoustonStreet, or if HoustonStreet fails to
grow  its revenues and net income, BayCorp could lose all of  the
value of its investment in HoustonStreet.

Item 3.  Quantitative and Qualitative Disclosures About Market
Risk

Commodity Price Risk

  Great  Bay Power Marketing is a party to the Unitil PPA,  which
as  amended, provides for the sale of 9.06 MWs of power to Unitil
at  $50.34  MWh through October 31, 2010.  Unitil had an  option,
which  expired November 1, 2005, to extend the Unitil PPA for  up
to  12  years,  from November 1, 2010 through October  30,  2022.
Unitil  did not exercise this option.  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

                               28

<Page>

Marketing  had net unrealized losses in the first nine months  of
2005   and  2004  of  approximately  $8,878,000  and  $3,000,000,
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
September  30,  2005 and 2004 and the unrealized loss  for  those
periods.

                                September 30,     September 30,
                                     2005             2004
                                _____________     _____________
                                      (Dollars in thousands)
      Fair Value                    ($12,499)        ($3,194)
      Unrealized Gain (Loss)         ($9,076)        ($3,198)

Item 4. Controls and Procedures

 Evaluation of Disclosure Controls and Procedures

  The  Chairman,  CEO, and President and the  Vice  President  of
Finance   of   the  Company  have  reviewed  and  evaluated   the
effectiveness of disclosure controls and procedures  (as  defined
in the Securities Exchange Act of 1934 (the "Exchange Act") Rules
240.13a and 15(e)) as of the end of the fiscal quarter covered by
this  Quarterly Report.  Based on that evaluation, the  Chairman,
CEO,  and  President  and  the Vice  President  of  Finance  have
concluded  that their current disclosure controls and  procedures
are,  in  all material respects, effective and timely,  providing
them  with material information relating to that required  to  be
disclosed  in the reports the Company files or submits under  the
Exchange Act.

  The  Company's  management, including  the  Chairman,  CEO  and
President and the Vice President of Finance, does not expect that
the  Company's disclosure controls and procedures or its internal
controls will prevent all error and all fraud.  A control system,
no  matter  how well conceived and operated, provides reasonable,
not absolute, assurance that the objectives of the control system
are  met.   The  design  of  a control system  reflects  resource
constraints; the benefits of controls must be considered relative
to  their  costs. Because there are inherent limitations  in  all
control  systems, no evaluation of controls can provide  absolute
assurance that all control issues and instances of fraud, if any,
within the Company have been or will be detected.  These inherent
limitations  include  the realities that judgments  in  decision-
making  can be faulty and that breakdowns occur because of simple
error or mistake.  Controls can be circumvented by the individual
acts  of some persons, by collusion of two or more people, or  by
management override of the control.  The design of any system  of
controls  is  based  in part upon certain assumptions  about  the
likelihood of future events.  There can be no assurance that  any
design  will  succeed  in achieving its stated  goals  under  all
future  conditions;  over time, controls  may  become  inadequate
because  of changes in conditions or deterioration in the  degree
of  compliance with the policies or procedures.  Because  of  the
inherent   limitations  in  a  cost-effective   control   system,
misstatements  due  to  error  or fraud  may  occur  and  not  be
detected.

Changes in Internal Controls

  There  have  not  been  any 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.


                               29

<Page>


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 September 30, 2005:


<Table>
<Caption>

                                                                        Maximum Number
                                            Total Number of Shares    of Shares that May
                              Average        Purchased as Part of      Yet Be Purchased
                 Shares        Price       Publicly Announced Plans   Under the Plans or
   Period     Repurchased    Per Share           or Programs             Programs (1)
________________________________________________________________________________________

     <S>          <C>           <C>                  <C>                     <C>
  July 1  -
September 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 5. Other Information

Change in Control of Registrant

  On  October  12,  2005,  Sloan Acquisition  Corp.,  a  Delaware
corporation  (the "Purchaser") and a wholly owned  subsidiary  of
Sloan  Group  Ltd., a Bahamas international business  corporation
("Sloan  Group"),  disclosed  in  a  Tender  Offer  Statement  on
Schedule  TO ("Schedule TO"), its offer to purchase  all  of  the
issued and outstanding shares of the Company's common stock at  a
price of $14.19 per share, net to the seller in cash, (the "Offer
Price") upon the terms and subject to the conditions set forth in
the Offer to Purchase (the "Offer to Purchase") dated October 12,
2005 and supplemented on November 4 and November 9, 2005, and  in
the related Letter of Transmittal (which, together with the Offer
to Purchase, constitute the "Offer").

  The  Offer  was  made  pursuant to  the  Amended  and  Restated
Agreement and Plan of Merger, dated as of September 30, 2005,  by
and among Sloan Group, the Purchaser and the Company (the "Merger
Agreement").  The Merger Agreement provides that as  promptly  as
practicable  after  the purchase of the shares  pursuant  to  the
Offer  and  the  satisfaction or, if permissible, waiver  of  the
other  conditions  set  forth in the Merger Agreement,  Purchaser
will  be merged with and into the Company (the "Merger").   As  a
result  of the Merger, the Company will continue as the surviving
corporation  (the "Surviving Corporation") and will be  a  wholly
owned  subsidiary of Sloan Group.  At the effective time  of  the
Merger,  each  share  of the Company's common  stock  issued  and
outstanding  immediately prior to the Effective Time (other  than
Common Stock held in the treasury of the Company or by Purchaser,
Sloan  Group or any direct or indirect subsidiary of Sloan  Group
or  the Company, and other than Common Stock held by stockholders
who  shall  have  demanded and perfected appraisal  rights  under
Delaware Law)  will be canceled and converted automatically  into
the right to receive $14.19 in cash.  The Merger Agreement, along
with employment agreements that the Company had entered into with
Frank  W.  Getman Jr. and Anthony M. Callendrello,  provide  that
following  consummation  of  the Merger,  the  directors  of  the
Purchaser  and  Messrs.  Getman  and  Callendrello  will  be  the
directors of the surviving company.

  The  Offer, as extended, expired at 12:00 midnight Eastern time
on  Thursday, November 10, 2005.  Parent and Purchaser have  been
advised  by SunTrust Bank, which is serving as the Depository  in
connection  with  the  Offer, that as of the  expiration  of  the
Offer,  a  total of 499,310 shares were tendered  in  the  offer,
including  1,036 covered by notices of guaranteed  delivery.   On
November  11,  2005, the Purchaser has accepted for purchase  and
payment all shares validly tendered and not withdrawn pursuant to
the  Offer.  The tendered shares, together with the 25,000 shares
previously  held  by Sloan Acquisition Corp. and its  affiliates,
represent approximately 91.7% of the outstanding common stock  of
the Company.


                               30

  <Page>

  As  a  result  of  the tender of shares and the acceptance  for
purchase  and  payment  of  all tendered  shares,  the  Purchaser
beneficially   owns  approximately  91.7  %  of   the   Company's
outstanding   shares,  for  which  it  has   paid   approximately
$7,070,500   (excluding  from  that  amount  shares   that   were
beneficially  owned by the Purchaser prior to  the  Offer).   The
source of the funds used by the Purchaser for payment was capital
contributed by Sloan Group, from available cash.

Item 6.  Exhibits

  See Exhibit Index.


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<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.


November 14, 2005           /s/ Frank W. Getman Jr.
                         ______________________________
                         Frank W. Getman Jr.
                         President and Chief Executive Officer
                         and Principal Financial Officer



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<Page>

                          EXHIBIT INDEX



  Exhibit
  No.           Description
  _______       ___________

    2.1    Agreement  and  Plan of Merger dated as of  September  13,
           2005  among BayCorp Holdings, Ltd., Sloan Group, Ltd.  and
           Sloan  Acquisition  Corp., filed as  Exhibit  2.1  to  the
           Company's  Current Report on Form 8-K (File  No.  1-12527)
           on   September  16,  2005  and  incorporated   herein   by
           reference.

    2.2    Amended  and  Restated Agreement and Plan of Merger  dated
           as  of  September  30, 2005 among BayCorp Holdings,  Ltd.,
           Sloan  Group  Ltd. and Sloan Acquisition Corp.,  filed  as
           Exhibit  2  to the Company's Current Report  on  Form  8-K
           (File  No.  1-12527) on October 6, 2005  and  incorporated
           herein by reference.

    2.3    Stockholder  Support Agreement dated  September  13,  2005
           among  Sloan Group Ltd., Sloan Acquisition Corp. and Frank
           W.  Getman  Jr.  and  Anthony M.  Callendrello,  filed  as
           Exhibit  2.2 to the Company's Current Report on  Form  8-K
           (File  No. 1-12527) on September 16, 2005 and incorporated
           herein by reference.

    2.4    Employment  Agreement  dated September  13,  2005  between
           BayCorp  Holdings, Ltd. and Frank W. Getman Jr., filed  as
           Exhibit  2.3 to the Company's Current Report on  Form  8-K
           (File  No. 1-12527) on September 16, 2005 and incorporated
           herein by reference.

    2.5    Employment  Agreement  dated September  13,  2005  between
           BayCorp Holdings, Ltd. and Anthony M. Callendrello,  filed
           as  Exhibit 2.4 to the Company's Current Report on Form 8-
           K   (File   No.  1-12527)  on  September  16,   2005   and
           incorporated herein by reference.

    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.

    4.1    $7,750,000  Promissory  Note from BayCorp  Holdings,  Ltd.
           and  its  wholly  owned subsidiaries to Sloan  Group  Ltd.
           dated  October  7,  2005, filed  as  Exhibit  4.1  to  the
           Company's  Amended Current Report on Form 8-K/A (File  No.
           1-12527)  on October 11, 2005 and incorporated  herein  by
           reference.

    4.2    Second   Amended  and  Restated  Pledge  Agreement   among
           BayCorp Holdings, Ltd., its wholly owned subsidiaries  and
           Sloan  Group Ltd. dated October 7, 2005, filed as  Exhibit
           4.2  to the Company's Amended Current Report on Form 8-K/A
           (File  No.  1-12527) on October 11, 2005 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.


                                  33


   <Page>


    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 September 30, 2005




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