<PAGE>


                                  UNITED STATES

                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                                    FORM 10-K


       (Mark One)

X    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
-    ACT OF 1934


                   For the fiscal year ended December 31, 2001

                                       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 000-25305

                          ENERGYNORTH NATURAL GAS, INC.
                   D/B/A/ KEYSPAN ENERGY DELIVERY NEW ENGLAND
             (Exact Name of Registrant As Specified In Its Charter)



         New Hampshire                                02-0209312
(State or other jurisdiction of             (I.R.S. Employer Identification No.)
Incorporation or Organization)

    One Beacon Street                              (617) 742-8400
    Boston, Massachusetts 02108               (Registrant's Telephone Number)
(Address of Principal Executive Offices)

          Securities registered pursuant to Section 12(b) of the Act:

       Title of Each Class                        Exchange
       -------------------                        --------
             None                                   None

           Securities registered pursuant to Section 12(g) of the Act:

                                      None

     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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
           -

     Indicate the mnumber of shares outstanding of the registrant class of
common stock as of March 1, 2002

       All common stock, 120,000 shares, are held by Eastern Enterprises.

     The registrant meets the conditions set forth in General Instruction
(I)(1)(a) and (b) of Form 10-K and is therefore filing this form with the
reduced disclosure format.

<PAGE>


                          ENERGYNORTH NATURAL GAS, INC.

                                    FORM 10-K

                       Fiscal Year Ended December 31, 2001

                                TABLE OF CONTENTS

<TABLE>
<CAPTION>

  Item
  No                                                       Topic                                                    Page
  --                                                       -----                                                    ----
<S>                                                                                                               <C>

                                                          PART I

  1.  Business

      General ...............................................................................................        1
      Markets and Competition ...............................................................................        2
      Gas Throughput ........................................................................................        2
      Gas Supply ............................................................................................        3
      Regulation ............................................................................................        3
      Seasonality and Working Capital .......................................................................        4
      Environmental Matters .................................................................................        5
      Employees .............................................................................................        5
  2.  Properties ............................................................................................        5
  3.  Legal Proceedings .....................................................................................        5
  4.  Submission of Matters to a Vote of Security Holders ...................................................        5
      Glossary ..............................................................................................        6

                                                        PART II

  5.  Market for the Registrant's Common Equity and Related Stockholder Matters .............................        7
  6.  Selected Financial Data ...............................................................................        7
  7.  Management's Discussion and Analysis of Financial Condition and Results of Operations .................        7
7.A   Quantitative and Qualitative Disclosures about Market Risk.............................................       10
  8.  Financial Statements and Supplementary Data ...........................................................       10
  9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ..................       10

                                                       PART III

10.   Directors and Executive Officers of the Registrant ....................................................       10
11.   Executive Compensation ................................................................................       10
12.   Security Ownership of Certain Beneficial Owners and Management ........................................       10
13.   Certain Relationships and Related Transactions ........................................................       10

                                                        PART IV

14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K .......................................       11

</TABLE>



<PAGE>


                                     PART I

Item 1.   Business.

General

     EnergyNorth Natural Gas, Inc. D/B/A KeySpan Energy Delivery New England
(the "Company"), is engaged in the transportation and sale of natural gas to
approximately 75,000 residential, commercial and industrial customers in 28
communities situated primarily in southern and central New Hampshire. The
Company was previously a wholly-owned subsidiary of EnergyNorth, Inc. ("ENI")
and has been in business for 56 years.

     The Company is a wholly-owned subsidiary of Eastern Enterprises
("Eastern"). On July 14, 1999, ENI and Eastern, a Massachusetts business trust,
entered into an Agreement and Plan of Reorganization ("Agreement") which
provided for the merger of ENI into Eastern by an exchange of stock. On November
4, 1999, Eastern entered into an agreement to merge with KeySpan Corporation
and, as a result, ENI and Eastern amended the Agreement. Under the amended
Agreement, holders of outstanding shares of ENI's common stock were paid
entirely in cash and the closing took place simultaneously with the Eastern
merger with KeySpan Corporation on November 8, 2000. KeySpan is a registered
holding company under the Public Utility Holding Company Act ("PUCHA") of 1935,
as amended. As a result, its activities, as well as certain activities of its
subsidiaries, including the Company, are regulated by the Securities and
Exchange Commission under PUHCA.

     For definition of certain industry-specific terms, see the Glossary at the
end of Part I and appearing on page 6.

     The Company distributes natural gas as a regulated utility pursuant to
franchise authority granted by the State of New Hampshire Public Utilities
Commission the ("Commission"). No operations are outside New Hampshire. The
Company offers firm and interruptible transportation service to its commercial
and industrial customers. Transportation service allows a customer to purchase
its natural gas supply directly from a third-party marketer. The marketer
delivers the gas supply to one of the Company's interstate pipeline gate
stations. The customer contracts with the Company to transport the gas from the
gate station to its facility. To ensure a continual, uninterrupted supply, the
Company also provides an optional, separate standby service as a backup to the
gas supplies of transportation customers.

     The Company has been providing gas transportation service, including
standby and balancing services, for commercial and industrial customers since
late 1993. Gas transportation service allows customers to utilize the Company's
distribution system for the transportation of gas purchased from third-party
suppliers, creating competition from gas marketers for the sale of gas to end
users. On March 15, 2001 the Commission issued an order requiring New Hampshire
local distribution companies ("LDC") to make transportation service available to
all commercial and industrial customers, separately from the purchase of gas
supply, which they may buy from third-party suppliers, by November 1, 2001. The
Company has done so. That order also establishes, that LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata basis
to marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that because of the migration of
customers to the gas supply of marketers, the costs of upstream interstate gas
pipeline capacity purchased by the Company to serve firm customers would be
absorbed by the LDC or other customers through the transition period. The order
further provided that the parties would reconvene in one year to address whether
and how the unbundling of transportation service should be made available to
residential customers.


                                       1

<PAGE>

Markets and Competition

     The Company competes with other fuel distributors, primarily oil dealers,
throughout its service territory. The principal competitive factors between
natural gas and alternative fuels are the price of the fuel and the conversion
costs from one fuel to another. Competition is greatest among the Company's
commercial and industrial customers, some of whom have the capability to use
alternative fuels. The Company provides flexible rates for users with duel-fuel
capabilities in order to better compete with the alternative fuels. The
Company's marketing focus continues to stress low cost growth by concentrating
on adding new customers along the Company's more than 1,000 miles of gas mains
and adding load from the existing customer base, while also expanding its system
of mains into areas in which there is a significant demand from natural gas
service.

Gas Throughput

     The following table in BCF provides information with respect to the volumes
of gas sold and transported by the Company during the three years 1999-2001.

<TABLE>
<CAPTION>

                                                                   Year Ended           Years Ended
                                                                  ------------   ----------------------------
                                                                  December 31,   September 30,  September 30,
                                                                      2001           2000           1999
                                                                  ------------   -------------  -------------
<S>                                                                 <C>            <C>           <C>
     Residential ...........................................           5.5            5.5            5.1
     Commercial and industrial .............................           5.4            5.1            4.8
     Off-system sales ......................................           0.8            0.8            0.5
                                                                      ----           ----           ----
          Total sales ......................................          11.7           11.4           10.4
     Transportation of customer-owned gas ..................           2.1            2.4            2.5
     Less: Off-system sales ................................          (0.8)          (0.8)          (0.5)
                                                                      ----           ----           ----
          Total throughput .................................          13.0           13.0           12.4
                                                                      ====           ====           ====
          Total firm throughput. ...........................          12.8           12.9           12.3
                                                                      ====           ====           ====
</TABLE>


     The above table excludes the effect of the accrual method of revenue
recognition as discussed in Note 1 of Notes to Consolidated Financial
Statements.

     In 2001, residential customers comprised 87% of the Company's customer
base, while commercial and industrial establishments accounted for the remaining
13%. Volumetrically, residential customers accounted for 42% of total firm
throughput, while commercial and industrial customers accounted for 66% of total
firm throughput. Approximately 28% of commercial and industrial customers' total
throughput was transportation-only service.

     No customer, or group of customers under common control, accounted for 2%
or more of total firm revenues in 2001.


                                       2

<PAGE>

Gas Supply

     The following table in BCF provides information with respect to the
Company's sources of supply during the three years 1999-2001.

<TABLE>
<CAPTION>
                                                                                       Year Ended      Years Ended
                                                                                      ------------    -------------
                                                                                      December 31,    September 30,
                                                                                         2001         2000     1999
                                                                                      ------------    -------------
<S>                                                                                     <C>          <C>      <C>
    Natural gas purchases and underground storage withdrawal ....................        11.3         11.3     10.5
    Liquefied natural gas ("LNG"), and liquefied petroleum ("LPG") purchases ....         2.8          0.3      0.1
                                                                                         ----         ----     ----
          Total source of supply .................................................       14.1         11.6     10.6
     Company use, unbilled and other .............................................       (2.4)        (0.2)    (0.2)
                                                                                         ----         ----     ----
           Total sales. ..........................................................       11.7         11.4     10.4
                                                                                         ====         ====     ====
</TABLE>

     Year-to-year variations in storage gas and unbilled gas reflect variations
in end-of-year customer requirements, due principally to weather.

     The Company's gas supply is principally natural gas, transported on
interstate pipelines. The primary pipeline the Company uses to bring natural gas
to its distribution territory is the Tennessee Gas Pipeline ("TGP"). The Company
has a contract for 56,833 Dekatherms ("Dth") of primary firm capacity on TGP.
The Company also has a long-term contract with a New England supplier for
additional firm city gate delivery of 8,000 Dth per day (151 day service). In
addition the Company contract for 1,000 Dth of primary firm capacity on Portland
Natural Gas Transmission System.

     In 2001, approximately 80% of the gas delivered by the Company came from
pipeline sources. Liquefied petroleum gas ("LPG") and liquefied natural gas
("LNG") purchases from both domestic and foreign sources made up approximately
20% of the gas delivered by the Company. LPG and LNG are vaporized at the
Company's peakshaving (production) plants as needed to supplement pipeline
natural gas supplies. Unbundled end-user customers that are supplied by
third-party marketers accounted for nearly 16% of total load on the Company's
system during 2001.

     All pipeline volumes to the Company's city gates are transported via the
TGP, except for volumes which are transported to the city gate at Berlin, New
Hampshire, by the Portland Natural Gas Transmission System. Canadian supplies
are also transported by the suppliers on the TransCanada Pipeline to the U.S.
border, where the Company takes possession in the United States. These volumes
are then transported on the Iroquois Gas Transmission System and the TGP. All
domestic pipelines operate under FERC-approved tariffs.

     The Company has underground storage agreements with four storage field
operators in the Pennsylvania-New York area. The Company fills these storage
fields each summer for use during the following winter. Total combined storage
controlled by the Company equals 2,580,131 Dth with daily withdrawal rights of
30,831 Dth. All underground storage fields operate under FERC-approved tariffs.
The Company also owns on-site storage facilities capable of holding 109,119 Dth
of LPG and 13,521 Dth of LNG. The Company has contracted for 450,000 Dth of
pipeline peaking service 50,000 Dth of LNG and 1,000,000 gallons of LPG for the
winter (2001/2002).

     The Company considers its peak day sendout capacity based on it total
supply resources to be adequate to meet the requirements of its firm customers.

Regulation

     The Company's operations are subject to regulation by the Commission, which
has authority over accounting, rates and charges, the issuance of securities and
certain operating matters. Changes in utility rates and charges cannot be made
without a 30-day notice to the Commission, which has the power to suspend,
investigate and change any proposed increase in rates and charges.


                                       3

<PAGE>

     The cost of gas rate authorized by the Commission permits dollar-for-dollar
recovery of gas costs (including pipeline, storage, LPG and LNG). The Company
may adjust the approved cost of gas rate upward or downward on a monthly basis.
The monthly accumulative adjustments may not exceed 20% of the approved unit
cost of gas sold. Amounts recovered through cost of gas charges are reconciled
twice annually against actual costs, for summer and winter periods, and future
cost of gas rates are adjusted accordingly.

     To prepare for the unbundling of gas supply and transportation service for
its customers, the Company filed a rate redesign proposal with the New Hampshire
Public Utilities Commission that was approved and became effective as of May 1,
2001. The rate redesign proposal is revenue neutral to the Company on an
annualized basis, although it increases base rates in the summer months offset
by decreased base rates in the winter months. The rate redesign also transfers
gas supply related costs from base rates to the cost of gas recovery mechanism.

     On March 15, 2001 the Commission issued an order requiring New Hampshire
local distribution companies ("LDC") to make transportation service available to
all commercial and industrial customers, separately from the purchase of gas
supply, which they may buy from third-party suppliers, by November 1, 2001. The
Company has done so. That order also establishes, that LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata basis
to marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that because of the migration of
customers to the gas supply of marketers, the costs of upstream interstate gas
pipeline capacity purchased by the Company to serve firm customers would be
absorbed by the LDC or other customers through the transition period. The order
further provided that the parties would reconvene in one year to address whether
and how the unbundling of transportation service should be made available to
residential customers.

     The migration of the customers from sales to transportation only service
has no effect on the Company's operating margin. Margins earned on interruptible
service, 280-day service and capacity releases are passed on to firm customers
through the cost of gas charge. In addition, costs associated with the financing
of inventory, including administrative fees and carrying costs, are recovered
through the cost of gas charge.

     The gas distribution business of the Company is subject to extensive safety
regulations and reporting requirements promulgated by the United States
Department of Transportation, but is not otherwise subject to direct regulation
by federal agencies except as to environmental matters. The Company is also
subject to zoning and other regulations by local authorities. Its capital
expenditures, earnings and operations have not been materially affected by
environmental and local regulation.

Seasonality and Working Capital

     The Company's revenues, earnings and cash flow are highly seasonal because
most of its transportation services and sales are directly related to
temperature conditions. Since the majority of its revenues are billed in the
November through March heating season, significant cash flows are generated from
late winter to early summer. In addition, through the cost of gas adjustment
clause, the Company bills its customers over the heating season for the majority
of the pipeline demand charges paid by the Company over the entire year. This
difference, along with other costs of gas distributed but unbilled, is reflected
as deferred gas costs and is financed through short-term borrowings. Short-term
borrowings are also required from time to time to finance normal business
operations. As a result of these factors, short-term borrowings are generally
highest during the late fall and early winter.


                                       4

<PAGE>

Environmental Matters

     The Company has or shares responsibility under applicable environmental law
for the remediation of former manufactured gas plant operations, including
former operating plants, gas holder locations and satellite disposal sites.
Information with respect to the remediation of these sites may be found in Note
8 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.

Employees

     As of December 31, 2001, the Company had approximately 100 employees, 67%
of whom are organized in local unions with which the Company has collective
bargaining agreements. These agreements expire in 2004.

Item 2. Properties.

     On December 31, 2001, the Company's distribution system included
approximately 1,200 miles of gas mains and 76,000 active customer meters.

     The Company's gas mains and services are usually located on public ways or
private property not owned by it. In general, the Company's occupation of such
property is pursuant to easements, licenses, permits or grants of location.
Except as stated above, the principal items of property of the Company are
owned.

     In 2001, the Company's capital expenditures were approximately $20 million.
Capital expenditures were principally made for improvements to the distribution
system, for system expansion to meet customer growth and for productivity
improvements. The Company plans to spend approximately $18 million for similar
purposes in 2002.

     .
Item 3. Legal Proceedings.

     Other than routine litigation incidental to the Company's business, there
are no material pending legal proceedings involving the Company.

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

     No matter was submitted to a vote of Security Holders in the fourth quarter
of 2001.


                                       5

<PAGE>

                                    Glossary

     BCF--Billions of cubic feet of natural gas at 1,000 Btu per cubic foot.

     Bundled Service--Two or more services tied together as a single product.
Services include gas sales at the city gate, interstate transportation, local
transportation, balancing daily swings in customer loads, storage, and
peak-shaving services.

     Capacity--The capability of pipelines and supplemental facilities to
deliver and/or store gas.

     City Gate--Physical interconnection between an interstate pipeline and the
local distribution company.

     Core Customer--Generally, customers with no readily available energy
services alternative.

     Dekatherm--1,000 cubic feet of natural gas at 1,000 Btu per cubic foot.

     Firm Service--Sales and/or transportation service provided without
interruption. This could be for the year, or for an agreed upon period less than
365 days. Firm services are provided under either filed rate tariffs or through
individually negotiated contracts.

     Gas Marketer (Broker)--A non-regulated buyer and seller of gas.

     Interstate Transportation--Transportation of gas by an interstate pipeline
to the city gate.

     Local Distribution Company (LDC)--A utility that owns and operates a gas
distribution system for the delivery of gas supplies from the city gate to
end-user facilities.

     Local Transportation Service--Transportation of gas by the LDC from the
city gate to the customer's burner tip.

     Non-Core Customers--Generally, those customers with readily available,
economically viable energy alternatives to gas.

     Non-Firm Service--Sales and transportation service offered at a lower level
of reliability and cost. Under this service, the LDC can interrupt customers on
short notice, typically during the winter season. Non-firm services are provided
through individually negotiated contracts and, in most cases, the price charged
takes into account the price of the customer's energy alternative.

     Throughput--Gas volume delivered to customers through the LDC's gas
distribution system.

     Unbundled Service--Service that is offered and priced separately, such as
separating the cost of gas commodity delivered to the LDC's city gate from the
cost of transporting the gas from the city gate to the end user. Unbundled
services can also include daily or monthly balancing, back-up or stand-by
services and pooling. With unbundled services, customers have the opportunity to
select only the services they desire.


                                       6

<PAGE>

                                     PART II

Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.

     Eastern Enterprises, a wholly-owned subsidiary of KeySpan Corporation, is
the holder of record of all the outstanding common equity securities of the
Company.

Item 6. Selected Financial Data.

     Not required.


Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.

RESULTS OF OPERATIONS

As discussed under Note 1 of Notes to Consolidated Financial Statements, the
Company became an indirect wholly-owned subsidiary of KeySpan Corporation when
its parent company, ENI, merged with KeySpan on November 8, 2000. ENI merged
into the Company in October, 2001. Therefore, the Company is now a wholly-owned
subsidiary of Eastern Enterprises ("Eastern").

Year ended December 31, 2001

     Net loss for the year was $4.3 million. Weather for this period was 7.6 %
warmer than normal. As a result of the merger, this period included a full year
of amortization of goodwill of $4.2 million and interest and debt issuance costs
of $6.3 million related to the $80 million advance from Keyspan.

Period from November 8, 2000 through December 31, 2000

     As a result of the merger, this period includes amortization of goodwill of
$.7 million and interest and debt issuance costs of $.7 million on the $80
million advance from KeySpan Corporation.

Period from October 1, 2000 through November 7, 2000

     This period includes merger-related expenses of approximately $11.6 million
consisting primarily of separation payments to officers, payment of vested stock
options and other compensation related matters associated with the KeySpan
merger.

Fiscal year ended September 30, 2000 Compared to fiscal year ended September 30,
1999

Net income in 2000 was $0.8 million compared to $3.8 million in 1999. The
decline in 2000 results was principally due to merger related expenses of $5.8
million, including special termination benefits and curtailment expenses of $2.2
million, payroll and related benefits of $1.7 million and other costs of $1.9
million. These were incurred as a result of the merger with Eastern Enterprises.

Operating revenues were $94.6 million in 2000 compared to $76.6 million in 1999.
The increase resulted primarily from a 6.6% increase in firm sendout and higher
gas costs. The average number of customers grew 2.3% and temperatures were
slightly colder than the prior year.

The cost of gas sold was $53.1 million in 2000 compared to $37.6 million in
1999. The increase was primarily due to timing differences related to the
recovery of gas costs through cost of gas charges, higher volumes of gas sold
and an increase in the unit cost. The average unit cost of gas sold in 2000
was $4.30


                                       7

<PAGE>

per Mcf compared to $3.78 per Mcf in 1999. Decreases or increases in purchased
gas costs from suppliers have no significant impact on margin, because they are
passed on to customers through the cost of gas charge.

Operations and maintenance expense for fiscal year 2000 were approximately 5%
greater than the prior year. Increased bad debt and other operating and
administrative costs were the primary cause.

Depreciation and amortization expense increased approximately 12% in 2000 and
reflects normal upgrades to the distribution system and related facilities and
increases in amortization of environmental remediation costs. Net additions to
property, plant and equipment were $10.6 million and $12 million in 2000 and
1999, respectively.

FORWARD-LOOKING INFORMATION

     Certain statements contained in this Annual Report on Form 10-K concerning
expectations, beliefs, plans, objectives, goals, strategies, future events or
performance and underlying assumptions and other statements that are other than
statements of historical facts, are " forward-looking statements" within the
meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Without limiting the foregoing, all statements under the captions "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" relating to our future outlook, anticipated capital expenditures,
future cash flows and borrowings, pursuit of potential future acquisition
opportunities and sources of funding, are forward-looking statements. Such
forward-looking statements reflect numerous assumptions and involve a number of
risks and uncertainties and actual results may differ materially from those
discussed in such statements. Among the factors that could cause actual results
to differ materially are: general economic conditions, especially in New
Hampshire, available sources and cost of fuel; federal and state regulatory
initiatives that increase competition, threaten cost and investment recovery,
and impact rate structures; the ability of the Company to successfully reduce
its cost structure; inflationary trends and interests rates; and other risks
detailed from time to time in other reports and other documents filed by the
Company with SEC. For any of these statements, the Company claims the protection
of the safe harbor for forward-looking information contained in the Private
Securities Litigation Reform Act of 1995, as amended. For additional discussion
on these risks, uncertainties and assumptions, see "Item 1. Business" and " Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations," and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" contained herein.

LIQUIDITY AND CAPITAL RESOURCES

     On November 8, 2000, KeySpan Corporate Services LLC, a KeySpan subsidiary,
became an affiliate of the Company, through the Company's transaction with
KeySpan. KeySpan Corporate Services provides financing requirements to the
Company for working capital and gas inventory through the Company's
participation in a Utility Money Pool. Interest charged equals interest incurred
by KeySpan Corporate Services to borrow funds to meet the needs of the Company
plus a proportional share of the administrative costs incurred in obtaining the
required funds.

     As part of the merger, the Company recorded in November 2000, a $80 million
advance payable to KeySpan. Interest charges equal interest incurred by KeySpan
on debt borrowings issued by KeySpan and recorded on the books of the Company.
Issuance expense is charged to the Company from KeySpan equal to the actual
issuance costs incurred by KeySpan on its debt borrowings. These costs are
amortized over the life of the borrowings.

     The Company expects capital expenditures for 2002 to be approximately $18
million. Capital expenditures will be largely for system expansion to meet
customer growth and improvements to the distribution system.

     The Company believes that projected cash flow from operations, in
combination with currently available resources, is sufficient to meet 2002
capital expenditures, working capital requirements, dividend payments and normal
debt repayments.


                                       8

<PAGE>

OTHER MATTERS

Regulation

     The Company's operations are subject to regulation by the Commission, which
has authority over accounting, rates and charges, the issuance of securities and
certain operating matters. Changes in utility rates and charges cannot be made
without a 30-day notice to the Commission, which has the power to suspend,
investigate and change any proposed increase in rates and charges.

     The cost of gas rate authorized by the Commission permits dollar-for-dollar
recovery of gas costs (including pipeline, storage, LPG and LNG). The Company
may adjust the approved cost of gas rate upward or downward on a monthly basis.
The monthly accumulative adjustments may not exceed 20% of the approved unit
cost of gas sold. Amounts recovered through cost of gas charges are reconciled
twice annually against actual costs, for summer and winter periods, and future
cost of gas rates are adjusted accordingly.

     To prepare for the unbundling of gas supply and transportation service for
its customers, the Company filed a rate redesign proposal with the New Hampshire
Public Utilities Commission that was approved and became effective as of May 1,
2001. The rate redesign proposal is revenue neutral to the Company on an
annualized basis, although it increases base rates in the summer months offset
by decreased base rates in the winter months. The rate redesign also transfers
gas supply related costs from base rates to the cost of gas recovery mechanism.

     On March 15, 2001 the Commission issued an order requiring New Hampshire
local distribution companies ("LDC") to make transportation service available to
all commercial and industrial customers, separately from the purchase of gas
supply, which they may buy from third-party suppliers, by November 1, 2001. The
Company has done so. That order also establishes, that LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata basis
to marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that because of the migration of
customers to the gas supply of marketers, the costs of upstream interstate gas
pipeline capacity purchased by the Company to serve firm customers would be
absorbed by the LDC or other customers through the transition period. The order
further provided that the parties would reconvene in one year to address whether
and how the unbundling of transportation service should be made available to
residential customers.

     The migration of the customers from sales to transportation only service
has no effect on the Company's operating margin. Margins earned on interruptible
service, 280-day service and capacity releases are passed on to firm customers
through the cost of gas charge. In addition, costs associated with the financing
of inventory, including administrative fees and carrying costs, are recovered
through the cost of gas charge.

     The gas distribution business of the Company is subject to extensive safety
regulations and reporting requirements promulgated by the United States
Department of Transportation, but is not otherwise subject to direct regulation
by federal agencies except as to environmental matters. The Company is also
subject to zoning and other regulations by local authorities. Its capital
expenditures, earnings and operations have not been materially affected by
environmental and local regulation.

Environmental Matters

     The Company has or shares responsibility under applicable environmental law
for the remediation of former manufactured gas plant operations, including
former operating plants, gas holder locations and satellite disposal sites.
Information with respect to the remediation of these sites may be found in Note
8 of Notes to Consolidated Financial Statements. Such information is
incorporated herein by reference.


                                       9

<PAGE>

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are subject to various risk exposures and uncertainties associated with our
operations. The most significant contingency involves the evolution of the gas
distribution industry towards more competitive and deregulated environments. In
addition, we are exposed to commodity price risk and interest risk. Set forth
below is a description of these exposures and an explanation as to how we have
managed and, to the extent possible, sought to reduce these risks.

Regulatory Issues and the Competitive Environment

     On March 15, 2001 the Commission issued an order requiring New Hampshire
local distribution companies ("LDC") to make transportation service available to
all commercial and industrial customers, separately from the purchase of gas
supply, which they may buy from third-party suppliers, by November 1, 2001. The
Company has done so. That order also establishes, that LDC contractual
commitments to upstream capacity will be assigned on a mandatory, pro rata basis
to marketers selling gas supply to the LDC's customers. The approved mandatory
assignment method eliminates the possibility that because of the migration of
customers to the gas supply of marketers, the costs of upstream interstate gas
pipeline capacity purchased by the Company to serve firm customers would be
absorbed by the LDC or other customers through the transition period. The order
further provided that the parties would reconvene in one year to address whether
and how the unbundling of transportation service should be made available to
residential customers.

     We believe that the actions described above strike a balance among
competing stakeholder interests in order to most effectively make available the
benefits of the unbundled gas supply market to all customers.

Item 8. Financial Statements and Supplementary Data.

     Information with respect to this item appears commencing on Page F-1 of
this Report. Such information is incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.

     None.


                                    PART III

Item 10. Directors and Executive Officers of the Registrant.

     Not required.


Item 11. Executive Compensation.

     Not required.


Item 12. Security Ownership of Certain Beneficial Owners and Management.

     Not required.


Item 13. Certain Relationships and Related Transactions.

     Not required.





                                       10

<PAGE>

                                     PART IV

Item 14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K.

List of Financial Statements and Financial Statement Schedules.

     Information with respect to these items appears on Page F-1 of this Report.
Such information is incorporated herein by reference.

(3)   List of Exhibits.

2.0  Agreement and Plan of Reorganization dated July 14, 1999 among Eastern
     Enterprises, EE Acquisition Company, and EnergyNorth, Inc. (Filed as
     Exhibit 2.0 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the
     fiscal year ended September 30, 1999).*

2.1  Amendment No. 1 to Agreement and Plan of Reorganization dated November 4,
     1999 (Filed as Exhibit 2.1 to EnergyNorth, Inc.'s Form 10-K (File No.
     1-11441) for the fiscal year ended September 30, 1999).*

3.1  Articles of Incorporation of EnergyNorth Natural Gas, Inc. (Filed as
     Exhibit 3.1 to EnergyNorth Natural Gas, Inc.'s Registration Statement on
     Form S-1, No. 333-32949, dated August 6, 1997).*

3.2  By-Laws of EnergyNorth Natural Gas, Inc., as amended (Filed as Exhibit 3.2
     to EnergyNorth Natural Gas, Inc.'s Amendment No. 2 to Registration
     Statement on Form S-1, No. 333-32949, dated September 17, 1997).*

4.1  Gas Service, Inc. General and Refunding Mortgage Indenture, dated as of
     June 30, 1987, as amended and supplemented by a First Supplemental
     Indenture, dated as of October 1, 1988, and by a Second Supplemental
     Indenture, dated as of August 31, 1989 (Filed as Exhibit 4.1 to
     EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year ended
     September 30, 1989).*

4.2  Third Supplemental Indenture, dated as of September 1, 1990, to Gas
     Service, Inc. General and Refunding Mortgage Indenture, dated as of June
     30, 1987 (Filed as Exhibit 4.2 to EnergyNorth, Inc.'s Form 10-K (File No.
     0-11035) for the fiscal year ended September 30, 1990).*

4.3  Fourth Supplemental Indenture, dated as of January 10, 1992, to Gas
     Service, Inc. General and Refunding Mortgage Indenture, dated as of June
     30, 1987 (Filed as Exhibit 4.3 of EnergyNorth, Inc.'s Form 10-K (File No.
     0-11035) for the fiscal year ended September 30, 1992).*

4.4  Fifth Supplemental Indenture, dated as of February 1, 1995, to Gas Service,
     Inc. General and Refunding Mortgage Indenture, dated as of June 30, 1987
     (Filed as Exhibit 4.4 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441)
     for the fiscal year ended September 30, 1996).*

4.5  Sixth Supplemental Indenture, dated as of September 15, 1997, to Gas
     Service, Inc. General and Refunding Mortgage Indenture, dated as of June
     30, 1987 (Filed as Exhibit 4.5 to EnergyNorth Natural Gas, Inc.'s Amendment
     No. 1 to Registration Statement on Form S-1, No. 333-32949, dated September
     10, 1997).*

10.1 Gas transportation agreement (FT-A), dated as of September 1, 1993, between
     Tennessee Gas Pipeline Company and EnergyNorth Natural Gas, Inc. (Filed as
     Exhibit 10.1 to EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the
     fiscal year ended September 30, 1993).*

10.2 Gas transportation agreement (Contract No. 632), dated as of September 1,
     1993, between Tennessee Gas Pipeline Company and EnergyNorth Natural Gas,
     Inc. (Filed as Exhibit 10.2 to EnergyNorth, Inc.'s Form 10-K (File No.
     0-11035) for the fiscal year ended September 30, 1995).*





                                       11

<PAGE>

10.3 Contract Restructuring Letter Agreement between Tennessee Gas Pipeline
     Company and EnergyNorth Natural Gas, Inc. effective November 1, 1999 (Filed
     as Exhibit 10.3 to EnergyNorth, Inc.'s Form 10-K (File No. 1-11441) for the
     fiscal year ended September 30, 1999).*

10.4 Tax Sharing Agreement, dated as of October 1, 1988, (Filed as Exhibit 10.21
     to EnergyNorth Natural Gas, Inc.'s Registration Statement on Form S-1, No.
     333-32949, dated August 6, 1997).*

10.5 Cost Allocation Agreement, dated as of October 1, 1996 (Filed as Exhibit
     10.22 to EnergyNorth Natural Gas, Inc.'s Amendment No. 2 to Registration
     Statement on Form S-1, No. 333-32949, dated September 17, 1997).*

99.1 Letter by the Company to the Securities and Exchange Commission regarding
     representations of Arthur Andersen LLP. (Filed Herewith).


     There were no reports on Form 8-K filed in the Fourth Quarter of 2001.

----------
*  Not filed herewith. In accordance with Rule 12(b)(32) of the General Rules
   and Regulations under the Securities Exchange Act of 1934, reference is made
   to the document previously filed with the Commission.


                                       12

<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                    ENERGYNORTH NATURAL GAS, INC.
                                    D/B/A KEYSPAN ENERGY DELIVERY NEW ENGLAND
                                    Registrant

                                                 JOSEPH F. BODANZA
                                  By:
                                         ------------------------------------
                                                 Joseph F. Bodanza
                                               Senior Vice President
                                    Finance, Accounting and Regulatory Affairs
                                   (Principal Financial and Accounting Officer)

Dated:   March 29, 2002

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on the 29th day of March, 2002.

            Signature                             Title
            ---------                             -----

         CHESTER R. MESSER                   Director and President
    -------------------------------
         Chester R. Messer


                                       13

<PAGE>


                          ENERGYNORTH NATURAL GAS, INC.

            INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES

            (Information required by Items 8 and 14 (a) of Form 10-K)

<TABLE>
<S>                                                                                               <C>
Report of Independent Public Accountants ........................................................       F-19
Consolidated Statements of Earnings for the Year Ended December 31, 2001, the Period from
     November 8, 2000 through December 31, 2000, the Period from October 1, 2000 through
     November 7, 2000, and the Years Ended September 30, 2000 and 1999                                   F-2
Consolidated Balance Sheets as of December 31, 2001 and 2000 ....................................    F-3 and F-4
Consolidated Statements of Retained Earnings and Consolidated Statements of
     Comprehensive Income for the Year Ended December 31, 2001, the period from
     November 8, 2000 through December 31, 2000, the Period from October 1, 2000
     through November 7, 2000, and the Years Ended September 31, 2000 and 1999...................         F-5
Consolidated Statements of Cash Flows for the Year Ended December 31, 2001, the
     Period from November 8, 2000 through December 31, 2000, the Period from
     October 1, 2000 through November 7, 2000, and the Years Ended September 30,
     2000 and 1999 ..............................................................................         F-6
Notes to Consolidated Financial Statements ......................................................    F-7 to F-18
Interim Financial Information for the Two Years Ended December 31, 2001 (Unaudited) .............       F-20
     Schedule for the Year Ended December 31, 2001, the Period from November 8,
     2000 through December 31, 2000, the Period from October 1, 2000 through
     November 7, 2000, and the Years Ended September 30, 2000 and 1999:
          Schedule II--Valuation and Qualifying Accounts ........................................      F-20 to F-22

</TABLE>

     Schedules other than that listed above have been omitted as the information
has been included in the consolidated financial statements and related notes or
is not applicable nor required.


                                       F-1

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                       CONSOLIDATED STATEMENTS OF EARNINGS

<TABLE>
<CAPTION>
                                                                     Period from   Period from
                                                                     November 8,   October 1,
                                                       Year Ended   2000 through  2000 through   Year Ended    Year Ended
                                                       December 31,  December 31,  November 7,  September 30, September 30,
                                                           2001          2000          2000          2000          1999
                                                           ----          ----          ----          ----          ----
                                                                                 (In Thousands)

                                                                                  (Predecessor) (Predecessor) (Predecessor)
<S>                                                   <C>           <C>          <C>            <C>           <C>

Operating revenues ...................................  $  129,784      $  26,473       $5,885   $   94,593      $ 76,617
Cost of gas sold .....................................      88,966         15,102        2,890       53,067        37,619
                                                        ----------     ----------   ----------   ----------    ----------
Operating margin .....................................      40,818         11,371        2,995       41,526        38,998
                                                        ----------     ----------   ----------   ----------    ----------
Operating expenses:
     Operations ......................................      18,614          3,320        1,599       15,377        14,669
     Maintenance .....................................       1,966            437          164        2,816         2,993
     Depreciation and amortization ...................       5,848          1,204          557        7,062         6,322
     Amortization of goodwill ........................       4,204            697           --           --           --
     Income taxes ....................................        (258)         1,616       (2,495)       2,147         2,740
     Taxes, other than income ........................       3,793            796          398        3,669         3,634
     Merger related expenses .........................          --            --        11,600        5,799         1,053
                                                        ----------     ----------   ----------   ----------    ----------
        Total operating expenses .....................      34,167          8,070       11,823       36,870        31,411
                                                        ----------     ----------   ----------   ----------    ----------
Operating earnings ...................................       6,651          3,301       (8,828)       4,656         7,587
Other earnings, net ..................................         501            133           48        1,093           849
                                                        ----------     ----------   ----------   ----------    ----------
   Earnings (loss) before interest expense ...........       7,152          3,434       (8,780)       5,749         8,436
                                                        ----------     ----------   ----------   ----------    ----------
Interest expense:
     Long-term debt ..................................       3,467          1,256          294        3,556         3,584
     Other, including amortization of debt expense ...       8,095            421          126        1,514         1,222
     Less--Interest during construction ..............        (146)           (11)          (5)        (117)         (201)
                                                        ----------     ----------   ----------   ----------    ----------
     Total interest expense ..........................      11,416          1,666          415        4,953         4,605
                                                        ----------     ----------   ----------   ----------    ----------
Net (loss) earnings . ................................  $   (4,264)     $   1,768   $   (9,195)  $      796    $    3,831
                                                        ===========     =========   ==========   ==========    ==========
</TABLE>




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


                                       F-2

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                           CONSOLIDATED BALANCE SHEETS

                                     ASSETS

<TABLE>
<CAPTION>
                                                                                                December 31,
                                                                                            --------------------
                                                                                             2001         2000
                                                                                            ------       -------
                                                                                               (In Thousands)
<S>                                                                                      <C>           <C>
Gas plant, at cost. ...................................................................     $189,510    $174,165
Construction work-in-progress .........................................................        5,604       3,784
     Less-Accumulated depreciation ....................................................      (63,903)    (60,080)
                                                                                            --------    --------
          Net plant ...................................................................      131,211     117,869
                                                                                            --------    --------
Current assets:
     Cash .............................................................................          320         193
     Accounts receivable, less reserves of $1,120 at December 31, 2001 and $1,399
        at December 31, 2000 ..........................................................        9,512      13,869
     Accounts receivable - affiliates .................................................        3,504          --
     Accrued utility margin ...........................................................        8,272      14,830
     Unbilled gas costs receivable ....................................................       (6,641)      1,337
     Natural gas and other inventories, at average cost ...............................        8,927       7,194
     Materials and supplies, at average cost ..........................................          793       1,054
     Prepaid expenses .................................................................          624       2,290
                                                                                            --------    --------
          Total current assets ........................................................       25,311      40,767
                                                                                            --------    --------
Other assets:
     Goodwill..........................................................................      162,881     167,509
     Deferred environmental ...........................................................       24,734       9,798
     Deferred charges and other assets ................................................        2,491       4,878
                                                                                            --------    --------
          Total other assets ..........................................................      190,106     182,185
                                                                                            --------    --------
          Total assets. ...............................................................     $346,628    $340,821
                                                                                            ========    ========

</TABLE>





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


                                       F-3

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                           CONSOLIDATED BALANCE SHEETS

                         CAPITALIZATION AND LIABILITIES

<TABLE>
<CAPTION>
                                                                                  December 31,
                                                                             --------------------
                                                                               2001        2000
                                                                             --------    --------
                                                                                 (In Thousands)
<S>                                                                      <C>               <C>
Capitalization:
     Common stockholder's investment--
        Common stock, $25 par value--
        Authorized and outstanding--120,000 shares ...................     $  3,000      $  3,000
     Amounts in excess of par value ..................................      110,653       114,558
     Retained earnings ...............................................       (2,497)        1,768
     Accumulated other comprehensive income ..........................       (3,255)           --
                                                                           --------      --------
          Total common stockholder's investment ......................      107,901       119,326
Long-term obligations, less current portion ..........................       33,789        41,582
                                                                           --------      --------
          Total capitalization .......................................      141,690       160,908
Advance from KeySpan .................................................       80,000        80,000
                                                                           --------      --------
Total capitalization and advance from KeySpan ........................      221,690       240,908
                                                                           --------      --------
Current liabilities:
     Current portion of long-term obligations ........................        7,333           389
     Notes payable - utility pool ....................................       55,622        41,085
     Notes payable - utility pool gas inventory financing ............       10,880        11,889
     Accounts payable ................................................        7,702        13,149
     Accounts payable--affiliates ....................................           --         6,278
     Accrued income taxes ............................................         (306)          359
     Accrued interest ................................................        2,404         2,125
     Customer deposits ...............................................          375           461
     Other ...........................................................       (1,272)        2,107
                                                                           ---------     --------
          Total current liabilities ..................................       82,738        77,842
                                                                           --------      --------
Reserves and deferred credits:
     Deferred income taxes ...........................................       17,011        18,548
     Unamortized investment tax credits ..............................        1,211         1,334
     Postretirement benefits obligation ..............................        4,163            --
     Other ...........................................................       19,815         2,189
                                                                           --------      --------
          Total reserves and deferred credits ........................       42,200        22,071
                                                                           --------      --------
          Total capitalization and liabilities. ......................     $346,628      $340,821
                                                                           ========      ========
</TABLE>



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


                                       F-4

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

<TABLE>
<CAPTION>
                                                                    Period from    Period from
                                                                   November 8,     October 1,
                                                     Year Ended    2000 through   2000 through   Year Ended    Year Ended
                                                    December 31,   December 31,    November 7,  September 30, September 30,
                                                        2001           2000           2000           2000         1999
                                                        ----           ----           ----           ----         ----
                                                                                (In Thousands)
                                                                                  (Predecessor) (Predecessor) (Predecessor)
<S>                                                <C>           <C>           <C>             <C>           <C>
Balance at beginning of period .............         $ 1,768        $    --       $15,888          $19,276     $19,265
     Net (loss) earnings ...................          (4,265)         1,768        (9,195)             796       3,831
     Cash dividends on common stock ........              --             --          (418)          (4,184)     (3,820)
                                                     -------        -------       -------          -------     ------
Balance at end of period....................         $(2,497)       $ 1,768       $(6,275)         $15,888     $19,276
                                                     =======        =======       =======          =======     =======
</TABLE>



                 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


<TABLE>
<CAPTION>
                                                                    Period from    Period from
                                                                   November 8,     January 1,    Four Months  Eight Months
                                                     Year Ended    2000 through   2000 through      Ended         Ended
                                                    December 31,   December 31,    November 7,   December 31,  August 31,
                                                        2001           2000           2000          1999          1999
                                                        ----           ----           ----          -----         ----
                                                                                (In Thousands)
                                                                               (Predecessor II) (Predecessor II)  Predecessor I)
<S>                                                <C>           <C>           <C>             <C>           <C>
Net (loss) earnings. .......................         $(4,265)       $ 1,768       $(9,195)         $   796     $ 3,831
Accrued unfunded pension obligation ........          (5,008)            --            --               --          --
Income tax effect ..........................           1,753             --            --               --          --
                                                     -------        -------       -------          -------     -------
Comprehensive (loss) income ................         $(7,519)       $ 1,768       $(9,195)         $   796     $ 3,831
                                                     ========       =======       =======          =======     =======
</TABLE>



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


                                       F-5

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                    Period from   Period from
                                                                   November 8,   October 1,
                                                      Year Ended  2000 through  2000 through   Year Ended    Year Ended
                                                     December 31,  December 31,  November 7,  September 30, September 30,
                                                         2001          2000          2000          2000         1999
                                                         ----          ----          ----          ----         ----
                                                                                (In Thousands)

                                                                                (Predecessor) (Predecessor) (Predecessor)

<S>                                                  <C>           <C>            <C>             <C>          <C>
Cash flows from operating activities:
   Net (loss) earnings ............................     $ (4,264)    $  1,768       $(9,195)        $   796       $ 3,831
   Adjustments to reconcile net earnings to cash
     provided by operating activities:
     Depreciation and amortization ................       10,052        1,901           557           7,458         6,877
     Deferred taxes ...............................       (6,435)         235        (1,780)           (118)        2,095
     Other changes in assets and liabilities:
        Accounts receivable .......................          853       (8,489)        2,290          (2,386)          719
        Accrued utility margin ....................        6,558       (2,035)       (1,421)           (108)          (43)
        Accounts payable--affiliates ..............       (6,278)     (14,730)        7,592           5,014         2,082
        Inventories ...............................       (1,472)       7,194        (1,680)         (2,774)          (98)
        Deferred gas costs ........................        7,978       (9,902)       (1,699)          1,081        (5,365)
        Accounts payable ..........................       (5,447)       2,869         3,841             766           303
        Accrued income taxes ......................        4,233        1,291          (932)          1,655          (649)
        Other .....................................        1,811          600           996          (2,693)       (4,767)
                                                        --------     --------       -------         -------       --------
          Cash (used for) provided by operating
             activities ...........................        7,589      (19,298)       (1,431)          8,691         4,985
                                                        --------     --------       -------         -------       -------
Cash flows from investing activities:
   Capital expenditures ...........................      (20,141)      (2,979)       (1,922)        (10,648)      (12,024)
                                                        --------     --------       --------        -------       -------
Cash flows from financing activities:
   Changes in notes payable, net ..................       14,537       21,085         2,700           3,122        12,287
   Changes in inventory financing .................       (1,009)        (736)        2,140           2,156          (383)
   Changes in other financing activities ..........         (849)         (35)           (5)            487          (462)
   Retirement of long-term debt, including premiums         --           --              --            (589)         (477)
   Issuance of long-term debt .....................         --           --              --             195            --
   Cash dividends paid on common stock ............         --           --            (418)         (4,184)       (3,820)
                                                        --------     --------       -------         -------       -------
          Cash provided by (used for) financing
             activities ...........................       12,679       20,314         4,417           1,187         7,145
                                                        --------     ---------      -------         -------       -------
Increase (decrease) in cash .......................          127       (1,963)        1,064            (770)          106
Cash at beginning of period .......................          193        2,156         1,092           1,862         1,756
                                                        --------     --------       -------         -------       -------
Cash at end of period .............................     $    320     $    193       $ 2,156         $ 1,092       $ 1,862
                                                        ========     ========       =======         =======       =======
Supplemental disclosure of cash flow information:
   Cash paid (refunded) during the year for:

          Interest, net of amounts capitalized ....     $ 11,868     $    414       $    64         $ 4,779       $ 4,330
                                                        ========     ========       =======         =======       =======
          Income taxes ............................     $  1,944     $   --         $  --           $ 1,612       $ 1,119
                                                        ========     ========       =======         =======       =======


</TABLE>


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


                                       F-6

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)   Accounting Policies

General

     EnergyNorth Natural Gas, Inc. (the "Company") is a gas distribution company
engaged in the transportation and sale of natural gas to residential, commercial
and industrial customers. The Company's service territory includes 28
communities situated primarily in southern and central New Hampshire. The
Company is a wholly-owned subsidiary of Eastern Enterprises ("Eastern") and an
indirect wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), a
registered holding company under the Public Utility Holding Company Act of 1935,
as amended. Prior to October, 2001 the Company was a subsidiary of EnergyNorth,
Inc. (ENI). In October, 2001, ENG merged into the Company.

Basis of Presentation

     The accounting policies of the Company conform to generally accepted
accounting principles and reflect the effects of the rate-making process in
accordance with Statement of Financial Accounting Standards No. 71 ("SFAS 71"),
"Accounting for the Effects of Certain Types of Regulation."

     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

Merger and Goodwill

     On July 14, 1999, ENI and Eastern, a Massachusetts business trust, entered
into an Agreement and Plan of Reorganization (Agreement) which provided for the
merger of ENI into Eastern by an exchange of stock. On November 4, 1999, Eastern
entered into an agreement to merge with KeySpan Corporation and, as a result,
ENI and Eastern amended the Agreement. Under the amended Agreement, holders of
outstanding shares of ENI's common stock were paid entirely in cash and the
closing took place simultaneously with the Eastern merger with KeySpan
Corporation on November 8, 2000. The Company expensed merger related costs of
$5.8 million, comprised of special termination benefits and curtailment expenses
of $2.2 million, payroll and related benefits of $1.7 million and other costs of
$1.9 million, during the year ended September 30, 2000. As a result of the
merger, the Company recorded as of October 31, 2000 approximately $6.0 million
of severance costs and benefits, $6.5 million of other merger related costs, and
write-offs of $1.9 million for assets, principally software, which were no
longer used or useful. A reduction of $0.4 million was recorded to goodwill in
finalizing the purchase price allocation, of which $3.9 million was a decrease
to equity.

     As prescribed by SFAS 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", the carrying value of
goodwill is reviewed if the facts and circumstances, such as significant
declines in sales, earnings or cash flows, or material adverse changes in the
business climate suggest it might be impaired. If this review indicates that
goodwill is not recoverable, as determined based upon the estimated undiscounted
cash flows of the equity acquired, impairment would be measured by comparing the
carrying value of the investment in such entity to its fair value. Fair value
would be determined based on quoted market values, appraisals, or discounted
cash flows. For the year ended December 31, 2001, no write-down of goodwill was
determined to be necessary.

     On January 1, 2002, the Company adopted SFAS 141, " Business Combinations",
and SFAS 142 "Goodwill and Other Intangible Assets". The key concepts from the
two interrelated Statements include mandatory use of the purchase method when
accounting for business combinations, discontinuance of goodwill amortization, a
revised framework for


                                       F-7

<PAGE>

                         ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


testing goodwill impairment at a "reporting unit" level, and new criteria for
the identification and potential amortization of other intangible assets. Other
changes to existing accounting standards involve the amount of goodwill to be
used in determining the gain or loss on the disposal of assets, and a
requirement to test goodwill for impairment at least annually. The annual
impairment test is to be performed within six months of adopting SFAS 142 with
any resulting impairment reflected as either a change in accounting principle,
or a charge to operations in the financial statements. The result of this
analysis is not complete at this time, and the Company is unable to determine
the impact this analysis may have on its results of operations or financial
condition. However, a change in the measurement of the realization of goodwill
could result in a significant change in the carrying value of goodwill.

Regulation

     The Company is regulated as to rates, accounting and other matters by the
State of New Hampshire Public Utilities Commission (the Commission). Therefore,
the Company accounts for the economic effects of regulation in accordance with
the provisions of SFAS No. 71. In the event the Company determines that it no
longer meets the criteria for following SFAS 71, the accounting impact would be
an extraordinary, non-cash charge to operations of an amount that could be
material. Management believes that this amount would approximate $24.7 million
as of December 31, 2001. Criteria that give rise to the discontinuance of SFAS
71 include (1) increasing competition that restricts the Company's ability to
establish prices to recover specific costs or (2) a significant change in the
manner in which rates are set by regulators from cost-based regulation to
another form of regulation. The Company has reviewed these criteria and believes
that the continuing application of SFAS 71 is appropriate.

     To prepare for the unbundling of gas supply and transportation service for
its customers, the Company filed a rate redesign proposal with the New Hampshire
Public Utilities Commission that was approved and became effective as of May 1,
2001. The rate redesign proposal is revenue neutral to the Company on an
annualized basis, although it increases base rates in the summer months offset
by decreased base rates in the winter months. The rate redesign also transfers
gas supply related costs from base rates to the cost of gas recovery mechanism.

     Effective November 1, 2001, all commercial and industrial customers of the
Company are allowed to purchase local transportation from the Company separately
from the purchase of gas supply, which they may buy from third party suppliers.

Gas Operating Revenues

     Customers are billed monthly on a cycle basis. Revenues include unbilled
amounts related to the estimated gas usage that occurred from the most recent
meter reading to the end of each month.

Cost of Gas Adjustment Clause and Unbilled Gas Costs Receivable

     The Company's tariff includes a cost of gas rate that permits billings to
recover its cost of gas. The tariff provides for a cost of gas rate calculation
for a summer period and a winter period. The Company may adjust the approved
cost of gas rate upward or downward on a monthly basis. The monthly cumulative
adjustments may not exceed 20% of the approved unit cost of gas sold. Any
difference remaining between the cost of gas distributed and amounts billed to
customers at the end of each period is deferred to a period in which the gas is
billed to customers. Interest accrues on these amounts at the prime rate,
adjusted quarterly.


                                       F-8

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(1) Accounting Policies (Continued)

Depreciation

     The Company provides for depreciation on the straight-line basis. The rates
applied are approved by the Commission. Such rates were equivalent to a
composite rate of 3.4% for the years ended December 31, 2001 and September 30,
2000 and 3.5% for the year ended September 30, 1999. Under depreciation
practices required by the Commission, when gas utility assets under the
composite method are retired from service, the cost of the retired assets is
removed from the property accounts and charged, together with any cost of
removal, to the accumulated depreciation accounts. For all other assets, when
assets are sold or retired, the cost of the assets and their related accumulated
depreciation are removed from the respective accounts, net removal costs are
recorded and any gain or loss is included in income.

   Recent Accounting Pronouncements

     In June of 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". The Standard requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity will capitalize a
cost increasing the carrying amount of the related long-lived asset. Over time,
the liability is accreted to its then present value, and the capitalized cost is
depreciated over the useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement. The standard is effective for fiscal
years beginning after June 15, 2002, with earlier application encouraged. The
Company is currently evaluating the impact, if any, that the Statement may have
on our results of operations and financial condition.

     SFAS 144, " Accounting for the Impairment of Disposal of Long-Lived
Assest," is effective January 1, 2002, and addresses accounting and reporting
for the impairment of disposal of long-lived assets. SFAS 144 supersedes SFAS
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and APB Opinion No. 30, "Reporting the Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business." SFAS
144 retains the fundamental provisions of SFAS 121 and expands the reporting of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal transaction.
We currently do not anticipate that implementation of this Statement will have a
significant effect on our results of operation and financial condition.

Reclassifications

     Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.


                                       F-9

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(2)        Income Taxes

     For 2001, the Company will file a consolidated federal income tax return
with KeySpan Corporation. Under the KeySpan tax sharing agreement the allocation
of the realized tax liability or benefit on the federal consolidated return will
be based upon separate return contributions of each company in the consolidated
group to the consolidated taxable income or loss. For the fiscal year ended
September 30, 2000, and for the period ended November 7, 2000, the company filed
a consolidated return with its parent EnergyNorth, Inc. For these periods the
Company followed the policy, established for the group, of providing for income
taxes payable on a separate company basis. The Company's effective tax rate
(benefit) was (5.7%) for the year ended December 31, 2001, 47.8% for the period
from November 8, 2000 to December 31, 2000, (21.3)% for the period from October
1, 2000 to November 7, 2000, and 73.0% for the fiscal year ended September 30,
2000, and 41.7% for the fiscal year ended September 31, 1999. Nondeductible
goodwill amortization represents the majority of the difference between the
effective rate and the federal income tax rate of 35% for 2001

     Nondeductible reorganization costs represent the majority of the difference
between the statutory rate and the effective rate for the period ended
December 31, 2000 and year ended September 30, 1999.

     A summary of the provision for income taxes is as follows:

<TABLE>
<CAPTION>

                                                               Period from     Period from
                                                               November 8       October 1
                                                Year Ended       through         through       Year Ended      Year Ended
                                              December 31,    December 31,     November 7,    September 30,   September 30,
                                                   2001            2000            2000           2000            1999
                                                   ----            ----            ----           ----            ----
                                                                             (In Thousands)
                                                                              (Predecessor)  (Predecessor)   (Predecessor)
<S>                                           <C>               <C>           <C>              <C>             <C>

Current--
     Federal ..............................     $ 4,916           $1,155        $  (574)         $2,145          $ (753)
     State ................................       1,261              246           (132)            497            (276)
                                                --------          ------        -------          ------          -------
          Total Current Provision .........       6,177            1,401           (706)          2,642          (1,029)
                                                --------          ------        -------          ------          ------
Deferred--
     Federal ..............................      (5,146)             176         (1,445)          (400)            2,996
     State ................................      (1,289)              39           (344)           (95)              773
                                                -------           ------        -------          -----           -------
          Total Deferred Provision ........      (6,435)             215         (1,789)          (495)            3,769
                                                -------           ------        -------          -----           ------
Provision for income taxes ................     $  (258)          $1,616        $(2,495)         $2,147          $ 2,740
                                                =======           ======-       =======          ======          =======

</TABLE>


     Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Income tax credits are
deferred and credited to income over the lives of the property giving rise to
such credits.


                                       F-10

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(2)   Income Taxes (Continued)

     For income tax purposes, the Company uses accelerated depreciation and
shorter depreciation lives, as permitted by the Internal Revenue Code. Deferred
federal and state taxes are provided for the tax effects of all temporary
differences between financial reporting and taxable income. Significant items
making up deferred tax assets and liabilities at December 31, 2001 and 2000 are
as follows:

<TABLE>
<CAPTION>

                                                                                 December 31,
                                                                          -------------------------
                                                                            2001             2000
                                                                          -------           --------
                                                                               (In Thousands)

<S>                                                                      <C>              <C>
Assets:

          Total deferred tax assets ...................................     $  7,274       $  $ 730
                                                                            --------       --------
Liabilities:

     Accelerated Depreciation .........................................      (16,951)       (16,068)
     Other ............................................................       (6,441)        (7,587)
                                                                            --------       --------
          Total deferred tax liabilities ..............................        23,392       (23,655)
                                                                            ---------      --------
          Total net deferred taxes ....................................     $(16,118)      $(22,925)
                                                                            ========       ========


Deferred income taxes are detailed in the balance sheet as follows:

Liabilities:

     Accrued income taxes (current)....................................     $    893      $  (4,377)
     Deferred income taxes (long-term) ................................      (17,011)       (18,548)
                                                                            --------      ---------
                                                                            $(16,118)     $ (22,925)
                                                                            ========      =========


</TABLE>




                                       F-11

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(3)   Debt

Long-term Obligations

     The following table provides information on long-term obligations as of:

<TABLE>
<CAPTION>

                                                                                December 31,
                                                                          -----------------------
                                                                            2001          2000
                                                                          ---------     ---------

                                                                             (In Thousands)

<S>                                                                       <C>            <C>
First Mortgage Bonds:
     8.44%, due 2009 ............................................           $  2,667       $ 3,000
     9.70%, due 2019 ............................................              7,000         7,000
     9.75%, due 2020 ............................................             10,000        10,000
     7.40%, due 2027 ............................................             21,455        21,872
Notes Payable ...................................................                 --            99
Less current portion ............................................             (7,333)         (389)
                                                                            --------       -------
                                                                             $33,789       $41,582
                                                                            ========       =======
</TABLE>


     Sinking fund requirements are $333,000 for each of the next five years.

     The first mortgage bonds are collateralized by first mortgage liens on
substantially all real property and operating plant facilities.

     The Company is not in compliance with one financial covenant on the 9.7%
bonds ($7 million). The Company is currently working with the holder of the
bonds to amend or waive this covenant; however, the Company is reflecting these
bonds as currently due until such amendment or waiver is received.

Utility Money Pool Borrowings

     On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through the Company's merger with KeySpan. KeySpan Corporate Services
provides financing to the Company for working capital and gas inventory through
the Company's participation in a Utility Money Pool. At December 31, 2001, the
Company had outstanding borrowings of $55,622,467 and $10,879,520 for working
capital and gas inventory, respectively. Interest charged equals interest
incurred by KeySpan Corporate Services to borrow funds to meet the needs of the
Company, plus a proportional share of the administrative costs incurred by
KeySpan in obtaining the required funds. All costs related to the gas inventory
borrowings are recoverable from customers through the CGAC. The average yearly
rate on these borrowings at December 31, 2001 was 4.16%.

Advance from KeySpan Corporation

     As part of the merger, the Company recorded in November, 2000 a $80 million
advance payable to KeySpan. Interest charges equal interest incurred by KeySpan
on debt borrowings issued by KeySpan and recorded on the books of the Company.
The interest rate on these borrowings is 7.25%. Issuance expense is charged to
the Company from KeySpan equal to the actual issuance costs incurred by KeySpan
on its debt borrowings. These costs are amortized over the life of the
borrowings.


                                       F-12

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

 (4)   Retiree Benefits

Pension Plans

     The Company has noncontributory defined benefit plans covering
substantially all employees. The Company's funding policy is to contribute
annually an amount that is not less than the minimum amount required by the
Employee Retirement Income Security Act of 1974 and not more than the maximum
amount deductible for income tax purposes. The net periodic pension cost was as
follows:

<TABLE>
<CAPTION>

                                                                 Period from   Period from
                                                                  November 8    October 1
                                                    Year Ended     through       through            Years Ended
                                                   December 31,  December 31,  November 7,         September 30,
                                                     2001          2000          2000          2000          1999
                                                     -------       -------       -------       -------       ----
                                                                             (In Thousands)
                                                                              (Predecessor) (Predecessor) (Predecessor)
<S>                                                 <C>            <C>          <C>            <C>          <C>
Service cost .....................................    $  594        $  108         $  25         $  254      $  274
Interest cost on projected benefits obligations ..     1,930           332            60            602         576
Expected return on plan assets ...................    (1,853)         (344)          (90)          (904)       (827)
Amortization of prior service cost ...............        --            --             6             56          56
Amortization of transitional obligation ..........        --            --            (6)           (60)        (60)
Recognized actuarial (gain) loss .................       121            --            --             --          --
Curtailment ......................................        --            --            --             --          --
                                                      ------         -----         -----         ------       -----
Total net pension cost ...........................    $  792         $  96         $  (5)        $  (52)      $  19
                                                      ======         =====         =====         ======       =====

</TABLE>

Post-retirement Life and Health Care

      The Company has a post-retirement benefit plan that covers substantially
all employees. The plan provides certain health and life insurance benefits. The
Company has funded these benefit costs by making cash contributions, at the same
level of expense recorded, to a Voluntary Employee Benefit Association (VEBA)
trust. The net periodic expense for post-retirement benefits other than pensions
was as follows:

<TABLE>
<CAPTION>
                                                                    Period from   Period from
                                                                     November 8    October 1
                                                       Year Ended     through       through            Years Ended
                                                      December 31,  December 31,  November 7,         September 30,
                                                        2001          2000          2000          2000          1999
                                                       -------       -------       -------       -------        ----
                                                                          (In Thousands)
                                                                           (Predecessor) (Predecessor) (Predecessor)
<S>                                                 <C>             <C>           <C>         <C>          <C>
Service cost ...................................       $  52          $ 22          $  5         $  48        $  52
Interest cost on accumulated benefits
obligations ....................................         211            73            18           178          167
Expected return on plan assets .................        (211)          (52)          (13)         (131)       $(124)
Amortization  of  net actuarial (gain) loss ....        (146)           --            14           140          140
Recognized actuarial (gain) loss ...............          --            --            (6)          (58)         (62)
                                                       -----          ----          ----         -----        -----
Net periodic benefit cost ......................       $ (94)         $ 43          $ 18         $ 177        $ 173
                                                       =====          ====          ====         =====        =====

</TABLE>





                                       F-13

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(4)        Retiree Benefits (Continued)

     The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's pension plans and
amounts recorded in the Company's balance sheet as of December 31, 2001,
December 31, 2000, November 7, 2000, and September 30, 2000. Actuarial
measurement dates are December 31, 2001, December 31, 2000, November 7, 2000,
and October 1, 1999, respectively.

<TABLE>
<CAPTION>

                                                                     Period from      Period from
                                                                      November 8       October 1
                                                  Year Ended           through         through            Year Ended
                                                  December 31,        December 31,      November 7,      September 30,
                                                      2001              2000              2000               2000
                                                      ----              ----              ----               ----
                                                                        (In Thousands)
                                                                                 (Predecessor)   (Predecessor)
<S>                                                  <C>            <C>            <C>                <C>
Pensions

Change in benefit obligation

Balance at beginning of period ....................    $28,451        $ 26,516         $ 8,478          $ 8,228
Service cost ......................................        594             108              26              254
Interest cost .....................................      1,930             333              68              602
Plan amendments ...................................      1,118             --              --               --
Curtailment loss ..................................        --              --              --                38
Special termination benefits ......................        --              --              --                23
Benefits paid .....................................     (2,099)           (72)             (26)            (364)
Addition of management plan at acquisition ........
Merger of ENI, Inc. ...............................        --              --           15,933               --
Actuarial (gain) loss .............................     (1,322)          1,566           2,037             (303)
                                                       -------        --------         -------          -------
Balance at end of period ..........................    $28,672        $ 28,451         $26,516          $ 8,478
                                                       =======        ========         =======          =======
Change in plan assets
Fair value, beginning of period ...................    $22,730        $ 24,351         $10,143          $ 9,835
Actual (loss) return on plan assets ...............     (2,141)         (1,550)             (5)             582
Employer contributions ............................        473               1              --              183
Benefits paid .....................................     (2,099)            (72)            (26)            (363)
Special termination benefits paid .................        --               --              --              (94)
Merger of ENI, Inc. ...............................        --               --          14,239               --
                                                       -------        --------        --------          -------
Fair value at end of period .......................    $18,963        $ 22,730        $ 24,351          $10,143
                                                       =======        ========        ========          =======
Reconciliation of funded status
Funded status .....................................    $(9,709)       $ (5,720)       $ (2,165)         $ 1,665
Unrecognized actuarial loss (gain) ................      6,012           3,461             --              (238)
Unrecognized transition obligation ................        --               --              --             (145)
Unrecognized prior service ........................      1,118              --              --              105
                                                       -------        --------        --------          --------
Net amount recognized at end of period ............    $(2,579)       $ (2,259)       $ (2,165)         $ 1,387
                                                       =======        ========        ========          =======
Amounts recognized in balance sheet
Prepaid benefit cost ..............................    $    00        $  1,165        $  1,183          $ 1,282
Accrued benefit liability .........................     (6,952)         (3,424)         (3,348)             105
Intangible asset ..................................      1,118              --             --                --
Accumulated other comprehensive income ............      3,255              --             --                --
                                                       -------        --------        ---------         --------
Net amount ........................................    $(2,579)       $ (2,259)       $  (2,165)        $ 1,387
                                                       =======        ========        ========          =======


</TABLE>



                                       F-14

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(4)        Retiree Benefits (Continued)

     Assets of the employee benefit plans are invested in domestic and
international equities, domestic and international fixed income securities, real
estate and other short-term debt instruments.

     The following tables set forth the change in benefit obligation and plan
assets and reconciliation of funded status of the Company's post-retirement life
and health benefit plans and amounts recorded in the Company's balance sheet as
of December 31, 2001, December 31, 2000, November 7, 2000 and September 30,
2000. Actuarial measurement dates are December 31, 2001, December 31, 2000,
November 7, 2000, and October 1, 1999, respectively.


<TABLE>
<CAPTION>

                                                               Period from      Period from
                                                                November 8       October 1
                                               Year Ended        through          through        Year Ended
                                               December 31,     December 31,     November 7,      September 30,
                                                 2001             2000             2000               2000
                                                 ----             ----             ----               ----
                                                                      (In Thousands)
                                                                               (Predecessor)   (Predecessor)

<S>                                              <C>               <C>              <C>             <C>

Healthcare

Change in benefit obligation

Balance at beginning of period ..............       $  5,753         $  5,130         $ 2,602          $ 2,453
Service cost ................................             52               22               5               48
Interest cost ...............................            211               73              21              178
Plan amendments .............................             --               --              --               --
Curtailment loss ............................             --               --              --              100
Special termination benefits ................             --               --              --               --
Benefits paid ...............................           (535)             (22)            (19)            (185)
Addition of management plan at acquisition ..             --               --           2,608               --
Actuarial (gain) loss .......................         (2,294)             550             (86)               8
                                                    --------         --------         -------           ------
Balance at end of period ....................       $  3,187         $  5,753         $ 5,131          $ 2,602
                                                    --------         --------         -------           ------
Change in plan assets
Fair value, beginning of period .............       $  3,395         $  3,704         $(1,453)         $ 1,369
Actual (loss) return on plan assets .........           (340)            (287)            146               93
Employer contributions ......................            116               --              --              176
Benefits paid ...............................           (535)             (22)            (19)            (185)
Merger of ENI, Inc. .........................             --               --           2,125               --
                                                    --------         --------         -------           ------
Fair value at end of period .................       $  2,636         $  3,395         $ 3,705          $ 1,453
                                                    ========         ========         =======          =======
Reconciliation of funded status
Funded status ...............................       $   (551)        $ (2,358)        $(1,426)         $(1,149)
Unrecognized actuarial (gain) loss ..........           (707)             890              --             (715)
Unrecognized transition obligation ..........             --               --              --            1,519
                                                    --------         --------         -------           ------
Accrued benefit liability ...................       $ (1,258)        $ (1,468)        $(1,426)         $  (345)
                                                    ========         ========         ========         =======

</TABLE>





                                       F-15

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(4)   Retiree Benefits (Continued)

     Following are the weighted-average assumptions used in developing the
projected benefit obligation:

<TABLE>
<CAPTION>

                                                     Period from     Period from
                                                       November 8      October 1
                                       Year Ended       through         through      Year Ended
                                      December 31,    December 31,    November 7,    September 30,
                                          2001           2000           2000           2000
                                          ----           ----           ----           ----
                                                                   (Predecessor)  (Predecessor)
<S>                                   <C>              <C>           <C>            <C>

Discount rate .......................     7.0%           7.0%           7.5%           7.75%
Return on plan assets ...............     8.5%           8.5%           8.5%           9.5%
Increase in future compensation .....     4.0%           5.0%           5.0%           4.0%
Health care inflation trend .........  5.0 - 10.0%       8.0%           8.0%        5.0 - 8.0%
</TABLE>


     The health care inflation rate for 2002 is assumed to be 10%. The rate is
assumed to decrease gradually to 5% in 2006 and remain at that level thereafter.
A one percentage point increase or decrease in the assumed health care trend
rate for 2001 would have no effect.

Unfunded Pension Obligations

         At December 31, 2001 accumulated benefit obligations were in excess of
pension assets. Pursuant to FAS 87 "Employers' Accounting for Pensions", the
Company was required to record an additional $5.1 million minimum liability for
this unfunded pension obligation. As allowed for under current accounting
guidelines, this accrual can be offset by a corresponding debit to a long-term
asset up to the amount of accumulated unrecognized prior service costs. Any
remaining amount is to be recorded as a direct charge to equity. Therefore, at
year-end, the Company recorded a $4.4 million debit in Deferred Charges Other
and a $0.7 million debit in Accumulated Other Comprehensive Income. In December
2002, we will re-measure the accumulated benefit obligations and pension assets,
and adjust the accrual and deferrals as appropriate.

(5)   Leases

     The Company leases certain facilities used in its operations and reflects
lease payments as rental expense in the periods to which they relate.

     Total rental expense for the year ended December 31, 2001 approximated
$735,000. Total rental expense for the period from November 8 through December
31, 2000 and the period from October 1 through November 7, 2000 approximated
$165,000 and $64,000, respectively. Total rental expense for the years ended
September 30, 2000 and 1999 approximated $606,000 and $735,000, respectively.
The company currently maintains no capital leases.


                                       F-16

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(6)   Fair Values of Financial Instruments

     The following methods and assumptions were used to estimate the fair values
of financial instruments:

          Cash--The carrying amounts approximate fair value.

          Short-term Debt--The carrying amounts of the Company's short-term
     debt, including notes payable and gas inventory financing, approximate
     their fair value.

          Long-term Debt--The fair value of long-term debt is estimated based on
currently quoted market prices.

     The carrying amounts and estimated fair values of the Company's long-term
debt at December 31, 2001 and 2000 are as follows:

<TABLE>
<CAPTION>

                                           2001                      2000
                                ------------------------    ---------------------------
                                Carrying                     Carrying
                                 Amount       Fair Value      Amount       Fair Value
                                 ------       ----------      ------       ----------
                                                    (In Thousands)
<S>                                 <C>          <C>          <C>           <C>

     Long-term debt. ..........  $41,122        $42,700       $41,971        $45,290

</TABLE>

(7)   Related Party Transactions

     In 2001, the Company was charged $5.5 million by KeySpan Corporate Services
LLC for services, which included: executive and administrative, corporate
affairs, customer services, environmental services, financial services
(including accounting, auditing, risk management, tax, treasury/finance), human
resources, information technology, legal, materials management and purchasing,
and strategic planning.

     KeySpan Corporate Services also purchases and/or develops and implements
software and purchase hardware which are or will be used by the Company. Capital
costs charged to the Company for these technology services totaled $383,000
during 2001.

     The Company was charged by Boston Gas Company $200,000 for the period
November 8, 2000 through December 31, 2000, and $3.6 million for the year ended
December 31, 2001, for administrative and customer related services rendered.
The Company was charged $8.7 million by ENI for the year ended September 30,
2000 for corporate services rendered.

     On November 8, 2000, KeySpan Corporate Services became an affiliate of the
Company, through the Company's merger with KeySpan. KeySpan Corporate Services
provides financing to the Company for working capital and gas inventory through
the Company's participation in a Utility Money Pool. At December 31, 2001, the
Company had outstanding borrowings of $55,622,000 and $10,880,000 for working
capital and gas inventory, respectively. In 2001, the Company paid KeySpan
Corporate Services $1,669,000 and $271,000 for interest on these working capital
and gas inventory borrowings, respectively. At December 31, 2000, the Company
had outstanding borrowings of $41,085,000 and $11,889,000 for working capital
and gas inventory borrowings, respectively. In 2000, the Company paid KeySpan
Corporate Services $225,000 and $62,000 for interest on these borrowings,
respectively. Interest charged equals interest incurred by KeySpan Corporate
Services to borrow funds to meet the needs of the Company, plus a proportional
share of the administrative costs incurred in obtaining the required funds.


                                       F-17

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(7)        Related Party Transactions (Continued)

     In November, 2000, the Company recorded a $80 million advance payable to
KeySpan. In 2001, the Company expensed $6.3 million for interest and debt
issuance costs on this advance. Interest charges equal interest incurred by
KeySpan on debt borrowings issued by KeySpan and recorded on the books of the
Company. Issuance expense is charged to the Company from KeySpan equal to the
actual issuance costs incurred by KeySpan on its debt borrowings. These costs
are amortized over the life of the borrowings.

(8)   Environmental Matters

     The Company and certain of its predecessors own or operated several
facilities for the manufacturing of gas from coal, a process used through the
mid-1900s that produced by-products that may be considered contaminated or
hazardous under current law, and some of which may still be present at such
facilities. The Company may have shared responsibility under applicable or
environmental laws for the remediation of 10 MGP sites and related facilities
associated with the historic operations of the Company. The Company has received
notice of its potential responsibility for contamination at two former MGP sites
and, together with other potentially responsible parties, had received notice of
potential responsibility for contamination associated with four other sites.

     With respect to the Laconia and Nashua sites, the Company has entered into
separate cost sharing agreements with Public Services of New Hampshire ("PSNH")
for the Laconia and Nashua sites. Under the agreements PSNH is obligated to
indemnify the Company for future remediation costs, with limited exceptions, at
the Laconia site and PSNH will pay the Company up to $4.8 million toward the
cost of the investigation and remediation at the Nashua site. The Company also
has entered into an agreement with the United States Environmental Protection
Agency ("EPA") for the contamination from the Nashua site that was allegedly
commingled with asbestos at the so-called Nashua River Asbestos Site, adjacent
to the Nashua MGP site.

     The Company has filed suit in both the New Hampshire Superior Court and the
United States District Court for the District of New Hampshire for recovery of
its remediation costs against the various insurance companies that issued
comprehensive general liability and excess liability insurance policies to the
Company and its predecessors. Settlements have been reached with some of the
carriers and one carrier was dismissed from a Superior Court action on summary
judgement. The outcome of the remaining proceedings cannot yet be determined.
The Company has also filed a contribution action in the United States District
Court for the District of New Hampshire against an entity the Company alleges
shares liability for the Manchester MGP study and remediation costs.

     We presently estimate the remaining cost of the Company's MGP-related
environmental cleanup activities will be $17.1 million, which amount has been
accrued by us as a reasonable estimate of probable cost for known sites.
Expenditures incurred since November 8, 2000 with respect to these MGP-related
activities total $2.9 million.

     The New Hampshire Public Utilities Commission has approved a recovery
mechanism for costs incurred at former manufacturing gas sites, which provides
for a seven-year recovery period of substantially all costs, excluding carrying
costs. The recovery mechanism provides that the environmental surcharge to
customers will not exceed 5% of total gross gas revenues in any given year but
that amounts in excess of 5% will be deferred to future periods with recovery of
applicable carrying costs


                                       F-18

<PAGE>

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To EnergyNorth Natural Gas, Inc.:

     We have audited the accompanying balance sheets and statements of
capitalization of EnergyNorth Natural Gas, Inc. (a New Hampshire corporation and
an indirect wholly-owned subsidiary of KeySpan Corporation) and subsidiary as of
December 31, 2001 and 2002, and the related consolidated statements of earnings,
retained earnings, comprehensive income, amd cash flows for the year ended
December 31, 2001, the period from November 8, 2000 through December 31, 2000,
the period from January 1, 2000 through November 7, 2000, and the year ended
December 31, 1999. These financial statements and the schedule referred to below
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and schedule based on our
audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of EnergyNorth
Natural Gas, Inc. and subsidiary as of December 31, 2001 and 2000, and the
results of its operations and its cash flows for the year ended December 31,
2001, the period from November 8, 2000 through December 31, 2000, the period
from January 1, 2000 through November 7, 2000 and the year ended December 31,
1999, in conformity with accounting principles generally accepted in the United
States.

     Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule under
part IV, Item 14, is presented for purposes of additional analysis and is not a
required part of the basic financial statements. This information has been
subjected to the auditing procedures applied in our audit of the basic financial
statements and, in our opinion, is fairly stated, in all material respects, in
relation to the basic financial statements taken as a whole.



                               ARTHUR ANDERSEN LLP



New York, New York
February 4, 2002


                                       F-19

<PAGE>

                          ENERGYNORTH NATURAL GAS, INC.

                          INTERIM FINANCIAL INFORMATION

              For the Two Years Ended December 31, 2001 (Unaudited)

<TABLE>
<CAPTION>

                                                                   Three Months Ended
                                                       ----------------------------------------------
                                                       March 31     June 30     Sept. 30     Dec. 31
                                                       --------     -------     --------     -------

                                                                       (In Thousands)
<S>                                                      <C>        <C>          <C>           <C>
2001

Operating revenues ...............................        $74,125     $16,471     $ 11,339      $ 27,849
Operating margin .................................        $18,820     $ 6,190     $  5,089      $ 10,719
Operating earnings (loss) ........................        $ 6,658     $  (963)    $   (472)     $  1,222
Net earnings (loss) applicable to common stock ...        $ 4,265     $(3,514)    $ (3,528)     $ (1,488)

</TABLE>


<TABLE>
<CAPTION>
                                                                                 Period from Period from
                                                     Three Months Ended           October 1  November 8
                                              ---------------------------------    through     through
                                              March 31     June 30     Sept. 30     Nov. 7     Dec. 31
                                              --------     -------     --------     ------     -------
                                            (Predecessor)(Predecessor(Predecessor(Predecessor)
                                                                   (In Thousands)
<S>                                           <C>         <C>          <C>         <C>         <C>
2000

Operating revenues ........................      $ 44,886    $16,212    $ 22,050     $ 5,885     $26,473
Operating margin ..........................      $ 19,458    $ 6,060    $ 10,686     $ 2,995     $11,371
Operating earnings (loss) .................      $  6,992    $(1,115)   $ (4,068)    $(8,828)    $ 3,301
Net earnings (loss) applicable
 to common stock ..........................      $  6,060    $(2,037)   $( 2,103)    $(9,195)    $ 1,768

</TABLE>



     In the opinion of management, the quarterly financial data includes all
adjustments, other than discussed in the accompanying notes, consisting only of
normal recurring accruals, necessary for a fair presentation of such
information.


                                       F-20

<PAGE>

                                   SCHEDULE II

                          ENERGYNORTH NATURAL GAS, INC.

                        VALUATION AND QUALIFYING ACCOUNTS

                                 (In Thousands)


<TABLE>
<CAPTION>



                                                                               Additions
                                                                               ---------              Net
                                                      Balance at      Charged        Charged      Deductions     Balance at
                                                      Beginning     (Credited)       to Other        from           End
           Description                                Of Period      to Income      Accounts       Reserves      Of Period
           -----------                                ---------      ---------      --------       --------      ---------

                      For the Year Ended December 31, 2001

<S>                                                  <C>            <C>             <C>           <C>           <C>

   Reserves for doubtful accounts .............         $  1,399     $  1,531       $     --        $ 1,810        $ 1,120
                                                        ========     ========       ========        =======        =======
   Reserve self-insurance .....................         $    104     $    220       $     --        $   189        $   135
                                                        ========     ========       ========        =======        =======
   Reserve for environmental expenses .........         $  2,107     $     --       $ 14,979        $   000        $17,086
                                                        ========     ========       ========        =======        =======
<CAPTION>


         For the Period From November 8, 2000 Through December 31, 2000
<S>                                                  <C>            <C>             <C>           <C>           <C>

   Reserves for doubtful accounts .............        $     998     $    418       $     --        $   17         $ 1,399
                                                       =========     ========       ========        =======        =======
   Reserve self-insurance .....................        $      79     $     25       $     --        $    --        $   104
                                                       =========     ========       ========        =======        =======
   Reserve for environmental expenses .........        $   2,107     $     --       $     --        $    --        $ 2,107
                                                       =========     ========       ========        =======        =======

<CAPTION>

          For the Period From October 1, 2000 Through November 7, 2000

                                  (Predecessor)
<S>                                                  <C>            <C>             <C>           <C>           <C>

   Reserves for doubtful accounts .............        $     877     $    119       $     --        $    (2)       $   998
                                                       =========     ========       ========        =======        =======
   Reserve self-insurance .....................        $      66     $     13       $     --        $    --        $    79
                                                       =========     ========       ========        =======        =======
   Reserve for environmental expenses .........        $   2,107     $     --       $     --        $    --        $ 2,107
                                                       =========     ========       ========        =======        =======

<CAPTION>

                      For the Year Ended September 30, 2000

                                  (Predecessor)
<S>                                                  <C>            <C>             <C>           <C>           <C>

   Reserves for doubtful accounts .............        $   1,069     $  1,276       $     --        $ 1,468        $   877
                                                       =========     ========       ========        =======        =======
   Reserve self-insurance .....................        $      34     $     41       $     --        $     9        $    66
                                                       =========     ========       ========        =======        =======
   Reserve for environmental expenses .........        $   4,132     $     --       $     --        $ 2,025        $ 2,107
                                                       =========     =======        ========        =======        =======

<CAPTION>

                      For the Year Ended September 30, 1999

                                  (Predecessor)
<S>                                                  <C>            <C>             <C>           <C>           <C>

   Reserves for doubtful accounts .............         $  1,088   $      880       $      --     $     899       $  1,069
                                                        ========   ==========       =========     =========       ========
   Reserve self-insurance .....................         $     55   $       --       $      --     $      21       $     34
                                                        ========   ==========       =========     =========       ========
   Reserve for environmental expenses .........         $  2,345   $       --       $   1,787     $      --       $  4,132
                                                        ========   ==========       =========     =========       ========
</TABLE>

     ---------------------
     (1)  Represents recoveries on accounts previously written off.




                                       F-21