<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended September 30, 2000
Commission File Number 000-25305
ENERGYNORTH NATURAL GAS, INC.
(Exact name of registrant as specified in its charter)
New Hampshire 02-0209312
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1260 Elm Street, P.O. Box 329, Manchester, New Hampshire 03105-0329
(603-625-4000)
(Address, zip code and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act: 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, 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. [ ]
At December 28, 2000, nonaffiliates held no shares of the registrant's $25.00
par value common stock, all of which was held by EnergyNorth, Inc.
At the close of business on December 28, 2000, the registrant had 120,000 shares
outstanding of its $25 par value common stock.
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.
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TABLE OF CONTENTS
Part I
<TABLE>
<CAPTION>
Page
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<S> <C>
Item 1. Business
General............................................................... 3
Market And Competition................................................ 4
Summary of Revenues................................................... 5
Deregulation.......................................................... 5
Gas Supply............................................................ 6
Regulation............................................................ 7
Seasonality and Working Capital....................................... 7
Environmental Matters................................................. 8
Employees............................................................. 8
Item 2. Properties............................................................. 8
Item 3. Legal Proceedings...................................................... 9
Item 4. Submission of Matters to a Vote of Security Holders.................... 9
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................................... 9
Item 6. Selected Financial Data................................................ 9
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.............................................. 10-12
Item 8. Financial Statements and Supplementary Data............................ 13-31
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................... 31
Part III
Item 10. Directors and Executive Officers of the Registrant..................... 31
Item 11. Executive Compensation................................................. 31
Item 12. Security Ownership of Certain Beneficial Owners and Management......... 31
Item 13. Certain Relationships and Related Transactions......................... 32
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....... 32-34
Signatures...................................................................... 35
Exhibit Index................................................................... 36-37
</TABLE>
2
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ENERGYNORTH NATURAL GAS, INC.
FORM 10-K
PART I
ITEM 1. BUSINESS
General
The business of EnergyNorth Natural Gas, Inc. (Company), incorporated in the
state of New Hampshire in 1945, is the purchase, transportation and sale of
natural gas for residential, commercial and industrial use in New Hampshire.
The Company is a wholly owned subsidiary of EnergyNorth, Inc. (ENI), a public
utility holding company, also incorporated in the state of New Hampshire. Both
the Company and ENI are headquartered at 1260 Elm Street, Manchester, New
Hampshire.
In general, the senior management of ENI serves as the senior management of the
Company. ENI provides for administrative support and services and establishes
policies, plans and goals.
On July 14, 1999, ENI and Eastern Enterprises (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 has 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.
The service territory of the Company has a population of approximately 499,000
in 28 communities situated primarily in southern and central New Hampshire. The
service area encompasses approximately 922 square miles and is mostly located
within 30 to 85 miles of greater Boston.
3
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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. While the Company's
franchise area is primarily residential in character, 56% of firm sales and
transportation volumes are commercial and industrial. As of September 30, 2000,
the Company served over 72,000 customers, of which approximately 88% were
residential and 12% were commercial and industrial. During fiscal 2000, no
customer accounted for 2% or more of the total annual sales and transportation
volume.
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
take stations. The customer contracts with the Company to transport the gas
from the take 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. As of September 30,
2000, the Company had 93 firm transportation customers.
The Company distributes gas to its customers through a system of underground
pipelines connected with its three operations centers in Manchester, Nashua and
Tilton, its seven take stations and its four production plant facilities. The
pipelines are generally located in public ways and are subject to licenses
granted by municipalities. The Company serves more than 75% of New Hampshire's
natural gas customers.
Market and Competition
Natural gas competes mainly with electricity and fuel oil. The principal
competitive factors are the price of competitive energy sources, the level of
investment required and customer perception of relative value. 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 dual-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 for natural gas service.
4
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Summary of Revenues
Revenues attributable to various categories of gas distribution and related
operations during the last three fiscal years are as follows (in thousands,
unaudited):
<TABLE>
<CAPTION>
September 30,
------------------------------
2000 1999 1998
------------------------------
<S> <C> <C> <C>
Sales service $90,950 $72,891 $82,686
Transportation service 3,643 3,726 2,610
Service and appliance 1,856 1,984 1,910
sales
Rentals 503 623 686
------------------------------
$96,952 $79,224 $87,892
==============================
</TABLE>
During the winter period, November 1 through March 31, the Company's gas
revenues are substantially higher than during the summer months. The increase
in gas revenues during the winter and the concomitant increase in gas supply
requirements occur because approximately 91% of the Company's customers use
natural gas for heating.
Deregulation
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. At September 30, 2000, the Company had 93 firm transportation customers.
These customers are, for the most part, large commercial and industrial
establishments. The volume transported for firm transportation customers in
fiscal 2000 was 2.2 Bcf, 17% of the Company's total firm sendout. The Company
is participating in a proceeding at the Commission to examine further unbundling
of the natural gas industry in New Hampshire. The purpose of the proceeding is
to determine whether and to what extent unbundling provides benefits to
customers and to make recommendations to the Commission as to the advisability
of further unbundling to commercial and industrial customers, as well as to
consider unbundling service to residential customers. The Company cannot
predict the outcome of the proceeding, or the impact on transportation volumes
or customers.
5
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Gas Supply
The Company's gas supply goal is to maintain a balanced portfolio of supply that
will continue to minimize the overall cost of gas while meeting the requirements
of its firm customers.
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
contracts for 56,833 Dekatherms (Dth) of primary firm and 8,000 Dth of
interruptible 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).
The Company's natural gas supply contracts are a mix of long- and short-term
agreements. The Company's firm supply contracts for fiscal year 2000, with
terms of one to seven years, totaled 40,529 Dth per day. During fiscal year
2000, approximately 3% of the Company's natural gas supply portfolio was firm
delivered winter supplemental supply. One percent of the Company's annual
supply in fiscal year 2000 was purchased in the spot market.
In fiscal year 2000, approximately 69% of the gas delivered by the Company came
from domestic pipeline sources, 18% from Canadian pipeline sources, and 12% from
supplemental pipeline sources. Liquefied petroleum gas (LPG) and liquefied
natural gas (LNG) purchases from both domestic and foreign sources made up
approximately 1% 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 17% of total load on the Company's
system during fiscal year 2000.
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 and transports
these supplies on the Iroquois Gas Transmission System, the Portland Natural 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 2,579,431 Dth with daily withdrawal rights of 28,115 Dth.
All underground storage fields operate under FERC-approved tariffs. The Company
also owns on-site storage facilities capable of holding 115,660 Dth of LPG and
13,057 Dth of LNG. The Company has contracted for 471,840 Dth of supplemental
pipeline supply, 100,000 Dth of LNG and 1,000,000 gallons of LPG for the
upcoming winter (2000/2001).
6
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The Company expects to be able to secure the gas supply required to meet
existing customer and forecasted new customer demands through long- and short-
term commitments and through spot purchases when needed.
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.
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 fuel inventory trust, 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 as 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.
7
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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 is participating with Public Service Company of New Hampshire (PSNH),
Northern Utilities and Central Vermont Public Service Company in the
investigation of a former manufactured gas site in Dover, New Hampshire. The
Company is participating with PSNH in the investigation of a former
manufacturing gas site in Nashua, New Hampshire, and has reached settlement with
PSNH on a site in Laconia, New Hampshire. The Company is also engaged in
remediation of a site in Concord, New Hampshire and investigation of a site in
Manchester, New Hampshire. Costs to complete the Company's share of site
investigation, risk characterization and remediation at manufacturing gas sites
are currently estimated to range from $2.1 million to $2.6 million. In addition
to costs incurred to date, the Company has recorded $2.1 million as a current
liability at September 30, 2000 with a corresponding charge to recoverable
environmental cost. The New Hampshire Public Utilities Commission has approved
a recovery mechanism for costs incurred at all former manufacturing gas sites,
except recovery for the Concord site, 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. The recovery mechanism for the Concord site provides for
recovery from customers, over a seven-year period, of substantially all costs,
excluding carrying cost.
Employees
At September 30, 2000, the Company had 76 full-time employees, represented by
two contracts with Local 12012 of the United Steelworkers of America. The
contracts expire in 2001. A substantial portion of the cost of ENI's 72 full-
time employees is allocated to the Company. None of ENI's employees are
represented by labor unions.
ITEM 2. PROPERTIES
The Company's gas distribution facilities constitute the majority of its
physical assets. As of September 30, 2000, the Company had approximately 1,130
miles of mains. The mains and service connections are adequate to meet service
requirements and are maintained through a regular program of inspection and
repair. There are office locations in Manchester and Tilton and operations
centers located in Nashua, Manchester, Concord and Tilton. They are adequate for
the needs of the Company and are regularly maintained and in good condition.
Substantially all of the Company's properties are fully utilized and are subject
to the liens of the indentures securing the Company's First Mortgage Bonds. In
some cases, motor vehicles are subject to purchase money security interests held
by banks. The Company also has long-term leases for computer equipment and
vehicles.
8
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ITEM 3. LEGAL PROCEEDINGS
In addition to the matters described in Environmental Matters, the Company is a
party in proceedings of the sort that arise in the ordinary course of its
business. Such actions, for the most part, are covered by insurance and, to the
extent that they are not fully covered, the damages sought are not material in
amount. The Company is a party to various routine Commission proceedings
relating to operations, none of which is expected to have a material impact on
the Company's earnings or assets.
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
fiscal 2000.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
(a) No equity securities of the Company were sold by it during the period
covered by this report. All 120,000 shares of the Company's outstanding
common stock are held by ENI.
ITEM 6. SELECTED FINANCIAL DATA
Not Required.
9
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Results of Operations 2000 Compared to 1999
Net income in 2000 was $.8 million compared to $3.8 million in 1999. The
decline in 2000 results were 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 $51.6 million in 2000 compared to $36.7 million in
1999. The increase was primarily due to timing differences related to the
recovery of gas costs through cost of gas charges ($6.0 million), higher volumes
of gas sold ($3.5 million) and an increase in the unit cost ($5.5 million). The
average unit cost of gas sold in 2000 was $4.30 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.
Results of Operations 1999 Compared to 1998
Net income declined to $3.8 million in 1999 from 1998 net income of $4.9
million. Impacting 1999 financial results were merger related expenses of $1.1
million incurred as a result of the merger with Eastern Enterprises.
Operating revenues were $76.6 million in 1999 compared to $85.3 million in 1998.
The decrease resulted primarily from lower gas costs. The average unit cost of
gas sold in 1999 was $3.78 per Mcf compared to $4.09 per Mcf in 1998.
Operations and maintenance expense for fiscal year 1999 was essentially
unchanged from the prior year. The warmer winter season resulted in lower
maintenance and bad debt expenses. Other operating and administrative cost
decreased as a result of effective cost containment efforts, which offset
increases in labor cost and health insurance and other employee benefit costs.
10
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Capital Resources and Liquidity
Because of the seasonal nature of the Company's operations, a substantial
portion of cash receipts is generated during the November - March heating
season, which results in the highest cash inflow during late winter and early
spring. Cash requirements for capital expenditures, dividends, long-term debt
retirement, environmental remediation and working capital do not track this
pattern of cash receipts. The greatest demand for cash is in the fall and early
winter to support the completion of the annual construction program and to fund
gas inventories and other working capital requirements.
At September 30, 2000, the Company had available lines of credit aggregating
$20.5 million, $17.3 million of which was outstanding. In addition, a credit
line of $10.5 million was available at September 30, 2000, under the Company's
fuel inventory trust financing plan. This credit line was increased to $15.5
million subsequent to September 30, 2000. At September 30, 2000, the Company's
outstanding purchase obligation in the fuel inventory trust was $10.5 million.
Capital expenditures for fiscal year 2001 are currently projected at
approximately $15 million. Additional cash requirements will be necessary for
the payment of dividends, environmental remediation, annual sinking fund
requirements and maturities of long-term debt and working capital. Cash to fund
these requirements is expected to be provided principally by internally
generated funds and short-term bank borrowings under the Company's lines of
credit.
Environmental Matters
The company continues to work with federal and state environmental agencies to
assess the extent and environmental impact of contaminants that may exist at or
near former gas manufacturing sites. The costs of such assessments and any
related remediation determined to be necessary is expected to be funded from
traditional sources of capital, recoveries from insurance carriers and
responsible third parties and customers. For further information, see Note 9 to
the financial statements.
New Accounting Standards and Pronouncements
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
establishes standards for recording all derivative instruments as assets and
liabilities measured at fair value. The standard was to be effective in the
first quarter of fiscal year 2000, but was amended by SFAS No. 137, "Accounting
for Derivative Instruments and Hedging Activities - Deferral of the Effective
Date of FASB Statement No. 133" - an amendment of FASB Statement 133. In
addition, SFAS No. 138, "Accounting for Certain Derivative Instruments and
Certain Activities", also amending SFAS No. 133 was issued in June 2000. As
such, SFAS No. 133, as amended, will be effective in the first quarter of fiscal
year 2001. The Company has reviewed its financial instruments and determined
that no disclosure under SFAS No. 133 is required.
11
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The American Institute of Certified Public Accountants issued Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed
and Obtained for Internal Use," and SOP 98-5, "Reporting on the Costs of Start-
up Activities." Both were effective in fiscal year 2000 and adoption did not
have a material impact on the Company's financial position.
Factors That May Affect Future Results
The Private Securities Litigation Reform Act of 1995 encourages the use of
cautionary statements accompanying forward-looking statements. The preceding
discussion of the Company's business and Management's Discussion and Analysis of
Financial Condition and Results of Operations include forward-looking statements
concerning the impact of changes in the cost of gas and cost of gas rates on
total margin; projected capital expenditures and sources of cash to fund
expenditures; the impact of regulatory proceedings on unbundling; estimated
costs of environmental remediation and anticipated regulatory approval of
recovery; competition with other forms of energy; and customer bypass. The
Company's future results, generally and with respect to such forward-looking
statements, may be affected by many factors, among which are uncertainty as to
the regulatory allowance of recovery of changes in the cost of gas; the impact
of merger-related activities; uncertain demands for capital expenditures and the
availability of cash from various sources; uncertainty as to whether
transportation rates will be reduced in future regulatory proceedings with
resulting decreases in transportation margins; uncertainty as to environmental
costs and as to regulatory approval of the full recovery of environmental costs
and other regulatory assets; weather; results of regulatory proceedings on
unbundling; impact of new pipeline supplies; costs of other sources of energy;
and customer bypass.
12
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
(a) Financial Statements required by Regulation S-X
<TABLE>
<CAPTION>
Statements of Income EnergyNorth Natural Gas, Inc.
(In thousands)
For the years ended 2000 1999 1998
September 30,
-------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues:
Utility gas service $93,666 $75,729 $84,274
Other 927 888 1,022
----------------------------------
Total operating revenues 94,593 76,617 85,296
----------------------------------
Operating expenses:
Cost of gas sold 51,639 36,636 46,693
Operations and maintenance 19,621 18,645 18,445
Depreciation and amortization 7,062 6,322 5,381
Taxes other than income taxes 3,669 3,634 3,738
Federal and state income taxes 2,147 2,740 2,812
Merger related expenses 5,799 1,053 -
----------------------------------
Total operating expenses 89,937 69,030 77,069
----------------------------------
Operating income 4,656 7,587 8,227
Other income, net 1,093 849 1,111
Interest expense:
Interest on long-term debt 3,556 3,584 3,628
Other interest 1,397 1,021 797
----------------------------------
Total interest expense 4,953 4,605 4,425
----------------------------------
Net income $ 796 $ 3,831 $ 4,913
==================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
13
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<TABLE>
<CAPTION>
Balance Sheets (In thousands) EnergyNorth Natural Gas, Inc.
September 30, 2000 1999
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Assets
Property:
Utility plant, at cost $177,708 $167,771
Accumulated depreciation and amortization 60,977 56,126
-----------------------
Net utility plant 116,731 111,645
-----------------------
Current assets:
Cash and temporary cash investments 1,092 1,862
Accounts receivable (net of allowances of $877 in 2000 and $1,069 in 1999) 3,495 1,109
Unbilled revenues 667 559
Deferred gas costs 443 1,524
Materials and supplies 1,114 1,505
Supplemental gas supplies 12,648 9,483
Prepaid and deferred taxes 356 2,415
Prepaid expenses and other 2,314 2,259
-----------------------
Total current assets 22,129 20,716
-----------------------
Deferred charges and other assets:
Regulatory asset - income taxes 2,746 2,465
Recoverable environmental costs 9,610 11,646
Other deferred charges and assets 2,142 2,200
-----------------------
Total deferred charges and other assets 14,498 16,311
-----------------------
Total assets $153,358 $148,672
=======================
Stockholder's equity and liabilities
Capitalization (see accompanying statements) $ 83,023 $ 86,807
-----------------------
Current Liabilities:
Notes payable to bank 17,300 14,178
Current portion of long-term debt 414 412
Inventory purchase obligation 10,485 8,329
Dividends payable 322 -
Accounts payable 5,417 4,973
Accounts payable to affiliates 9,241 4,227
Accrued interest 312 245
Accrued and deferred taxes 120 525
Accrued environmental remediation cost 2,107 4,132
Customer deposits and other 970 874
-----------------------
Total current liabilities 46,688 37,895
-----------------------
Deferred credits:
Deferred income taxes 20,725 20,326
Unamortized investment tax credits 1,364 1,487
Regulatory liability - income taxes 914 1,027
Long-term environmental remediation costs - 700
Contributions in aid of construction and other 644 430
-----------------------
Total deferred credits 23,647 23,970
-----------------------
Total stockholder's equity and liabilities $153,358 $148,672
=======================
</TABLE>
The accompanying notes are an integral part of these financial statements.
14
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Statements of Capitalization EnergyNorth Natural Gas, Inc.
<TABLE>
<CAPTION>
(In thousands, except share information)
September 30, 2000 1999
------------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization:
Common stockholder's equity:
Common stock - par value of $25 per share;
120,000 shares authorized, issued and outstanding $ 3,000 $ 3,000
Amount in excess of par value 22,538 22,538
Retained earnings 15,888 19,276
-------------------
Total common stockholder's equity 41,426 44,814
-------------------
Long-term debt:
First Mortgage Bonds
Due 2009 8.44% 3,000 3,333
Due 2019 9.70% 7,000 7,000
Due 2020 9.75% 10,000 10,000
Due 2027 7.40% 21,872 21,955
Notes payable
Due through 2001 at prime plus .50% 139 117
-------------------
42,011 42,405
Less current portion 414 412
-------------------
Total long-term debt 41,597 41,993
-------------------
Total capitalization $83,023 $86,807
===================
</TABLE>
The accompanying notes are an integral part of these financial statements.
15
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Statements of Retained Earnings EnergyNorth Natural Gas, Inc.
<TABLE>
<CAPTION>
(In thousands)
For the years ended September 30, 2000 1999 1998
--------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $19,276 $19,265 $18,155
Add - net income 796 3,831 4,913
-------------------------------
20,072 23,096 23,068
Deduct - cash dividends on common stock 4,184 3,820 3,803
-------------------------------
Balance at end of year $15,888 $19,276 $19,265
===============================
</TABLE>
The accompanying notes are an integral part of these financial statements.
16
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Statements of Cash Flows EnergyNorth Natural Gas, Inc.
<TABLE>
<CAPTION>
(In thousands)
For the years ended September 30, 2000 1999 1998
-----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $ 796 $ 3,831 $ 4,913
Noncash items:
Depreciation and amortization 7,458 6,877 5,837
Deferred taxes and investment tax credits, net (118) 2,095 292
Changes in:
Accounts receivable, net (2,386) 719 1,169
Unbilled revenues (108) (43) 86
Inventories (2,774) (98) (311)
Prepaid expenses and other (55) (231) (22)
Deferred gas costs 1,081 (5,365) 2,542
Accounts payable 766 303 (662)
Accounts payable to affiliates, net 5,014 2,082 (288)
Accrued liabilities (112) 11 (24)
Accrued/prepaid taxes 1,655 (649) (143)
Payments for environmental costs and other (2,526) (4,547) 257
------------------------------------
Net cash provided by operating activities 8,691 4,985 13,646
------------------------------------
Cash flows from investing activities:
Additions to property (10,648) (12,024) (13,123)
------------------------------------
Cash flows from financing activities:
Cash dividends on common stock (4,184) (3,820) (3,803)
Issuance of long-term debt 195 - -
Repayment of long-term debt (589) (477) (515)
Change in notes payable to banks 3,122 12,287 1,891
Change in inventory purchase obligation 2,156 (383) 860
Change in other financing activities 487 (462) 47
------------------------------------
Net cash provided by (used for) financing activities 1,187 7,145 (1,520)
------------------------------------
Net increase (decrease) in cash and temporary cash investments (770) 106 (997)
Cash and temporary cash investments, beginning of year 1,862 1,756 2,753
------------------------------------
Cash and temporary cash investments, end of year $ 1,092 $ 1,862 $ 1,756
====================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
17
<PAGE>
NOTES TO FINANCIAL STATEMENTS
Note 1. Accounting Policies
The significant accounting policies followed by EnergyNorth Natural Gas, Inc.
(Company) are set forth below.
Business Organization
---------------------
The Company is a wholly owned subsidiary of EnergyNorth, Inc. (ENI). As of
November 8, 2000, ENI merged with Eastern Enterprises which merged with KeySpan
Corporation (see Note 10). Transactions between the Company and other affiliated
companies include payments for management, accounting, data processing and other
services. The Company is a regulated gas distribution utility primarily located
in southern and central New Hampshire and also services and sells appliances.
The rates and accounting practices followed by the Company are regulated by the
State of New Hampshire Public Utilities Commission (the Commission). The
Company's accounting policies conform to generally accepted accounting
principles (GAAP) applicable to rate-regulated enterprises and reflect the
effects of the rate-making process in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for Certain Types of
Regulation," as amended.
Revenue Recognition
-------------------
Revenues derived from the sale and transportation of natural gas are based on
rates authorized by the Commission. Customers' meters are read and bills are
rendered on a cycle basis throughout the month. The Company records unbilled
revenues related to gas delivered but unbilled at the end of the accounting
period.
Cost of Gas Rates
-----------------
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.
Inventories
-----------
Inventories are valued on the basis of the lower of average cost or market.
18
<PAGE>
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 year ended September 30, 2000 and 3.5% and 3.4%
for each of the years ended September 30, 1999 and 1998, respectively. 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.
Deferred Charges
----------------
Total deferred charges consist primarily of regulatory assets and the cost of
issuing debt. The Company has established various regulatory assets in cases
where the Commission has permitted, or is expected to permit, recovery of
specific costs over a period of time. At September 30, 2000, regulatory assets
included $9.6 million for environmental investigation and remediation costs and
$2.7 million of unrecovered deferred state income taxes (see Note 6).
The unamortized cost of issuing debt at September 30, 2000 is $1.8 million.
Deferred financing costs are amortized over the life of the related security.
Other deferred charges are amortized over the recovery period specified by the
Commission.
Investment Tax Credits
----------------------
Investment tax credits are amortized over the estimated useful life of the
property that gave rise to the credit.
Fair Value of Financial Instruments
-----------------------------------
Because of the short maturity of certain assets, which include cash, temporary
cash investments and accounts receivable and certain liabilities, which include
accounts payable and notes payable to banks, these instruments are stated at
amounts that approximate fair value.
If long-term debt outstanding at September 30, 2000 had been refinanced using
new issue debt rates of interest that on average are lower than the outstanding
rates, the present value of those obligations would have increased from the
amounts outstanding in the September 30, 2000 accompanying balance sheet by
3.3%. In the event of refinancing, there would be no gain or loss as, under
established regulatory procedure, any such difference would be reflected in
rates and have no effect on income.
19
<PAGE>
Derivative Instruments and Hedging Activities
---------------------------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." In June
1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of the Effective Date of SFAS No. 133." In June
2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Activities," which was an amendment to SFAS Statement
No. 133. These statements establish accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at fair market value. These statements
require that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
SFAS No. 133, as amended, will be effective in the first quarter of fiscal year
2001. As of September 30, 2000, the Company has inventoried its contracts and
for each of those contracts has considered the impact of SFAS No. 133. Based on
such evaluation and work performed to date, SFAS No. 133, as amended, is not
expected to have a material effect on the financial position or results of
operations of the Company.
Affiliate Transactions
----------------------
The Company was charged by ENI $8.7 million in fiscal year 2000 for corporate
services rendered. In general, the senior management of ENI serves as the senior
management of the Company.
Included in the Balance Sheet at September 30, 2000 is Accounts Payable to ENI
in the amount of $9.2 million. A significant amount of the administrative
functions and supporting technology systems are integrated with those of ENI.
Use of Estimates
----------------
The preparation of financial statements in conformity with GAAP requires the use
of estimates and assumptions that affect assets and liabilities, the disclosure
of contingent assets and liabilities and revenues and expenses. Actual amounts
could differ from those estimates.
Reclassifications
-----------------
Certain prior year financial statement amounts have been reclassified for
consistent presentation with the current year.
20
<PAGE>
Note 2. Cash Flows
Supplemental disclosures of cash flow information were as follows (in
thousands):
2000 1999 1998
--------------------------------------------------------------------------------
Cash paid during the year for:
Interest, net of amount capitalized $4,779 $4,330 $3,957
Income taxes 1,612 1,119 2,761
In preparing the accompanying statements of cash flows, all highly liquid
investments having maturities of three months or less when acquired were
considered to be cash equivalents and classified as cash and temporary cash
investments.
Note 3. Inventory Purchase Obligation
The Company finances gas inventory purchases through the use of a single-purpose
trust, that purchases gas with funds loaned to it by a bank. As the Company
requires gas to service customers, gas is repurchased from the trust at original
product cost plus financing costs and trust fees. The cost of gas and related
financing are recoverable through the cost of gas charge.
The bank credit agreement provides for a 0.375% commitment fee on the credit
line and interest at prime (9.5% at September 30, 2000) with a fixed-rate
interest option at less than prime on the outstanding balance. The trust
agreement provides for a management fee of $8,000 annually. The credit agreement
between the trust and the bank provides for a total commitment of up to $10.5
million, which was increased to $15.5 million after September 30, 2000.
As of September 30, 2000 and 1999, the gas inventories under the trust agreement
and controlled by the Company totaled $11.4 million and $8.3 million,
respectively, and are included in inventories in the accompanying balance
sheets. Inventory purchase obligations under this financing agreement are
reflected as a current liability in the accompanying balance sheets.
Note 4. Notes Payable to Banks
As of September 30, 2000, the Company had $20.5 million available under various
unsecured bank lines of credit that are renewed annually, $17.3 million of which
was outstanding. The weighted average interest rate on borrowings outstanding on
September 30, 2000 was 7.23%. The lines bear interest at prime or less than
prime on certain of the lines for fixed periods of time, and are due on demand.
For some lines, the terms of the credit agreements require annual commitment
fees of .25% of the lines.
21
<PAGE>
Note 5. Long-Term Debt
Interest payments for the First Mortgage Bonds are due semiannually. The First
Mortgage Bonds are collateralized by first mortgage liens on substantially all
real property and operating plant facilities.
The aggregate amounts of principal due for all long-term debt for each of the
five years subsequent to September 30, 2000 are as follows (in thousands):
Fiscal year Amount
-------------------------------------------------------------------------------
2001 $414
2002 $391
2003 $333
2004 $333
2005 $333
Note 6. Income Taxes
The Company files a consolidated federal income tax return with its parent
company. For financial reporting and rate purposes, the Company provides taxes
on a separate return basis.
At September 30, 2000 and 1999, a SFAS No. 109 related regulatory liability
amounted to $756,000 and $824,000, respectively, for the tax benefit of
unamortized investment tax credits, and $159,000 and $203,000, respectively, for
excess deferred taxes as a result of pre-July 1, 1987 deferred income taxes that
were recorded in excess of the current federal statutory income tax rate.
A deferred state income tax liability and a corresponding regulatory asset of
approximately $2.7 million, representing revenues the Company expects to recover
from gas service customers, were established at September 30, 1994 as a result
of recording deferred state income taxes on the cumulative temporary differences
due to a change in New Hampshire tax law. Effective June 2, 1994, the 1%
franchise tax assessed on the sale of natural gas was repealed. Prior to the tax
law change, the franchise tax was permitted as a credit against the New
Hampshire Business Profits Tax (NHBPT). Because franchise tax payments exceeded
the NHBPT, the Company never incurred a NHBPT liability; therefore, no deferred
state income taxes related to temporary differences were recorded.
22
<PAGE>
The tax effects of cumulative differences that gave rise to the deferred tax
liabilities and deferred tax assets for the years ended September 30, 2000 and
1999 were as follows (in thousands):
2000 1999
------------------------------------------------------------------------------
Deferred tax assets:
Contributions in aid of construction $ 850 $ 794
Unamortized investment tax credits 464 506
Allowance for doubtful accounts 346 414
Deferred compensation 452 343
Other 625 433
---------------------
Total deferred tax assets 2,737 2,490
---------------------
Deferred tax liabilities:
Property-related 19,330 18,116
Environmental costs 1,979 2,645
Other 1,707 2,047
---------------------
Total deferred tax liabilities 23,016 22,808
---------------------
Net deferred tax liability $20,279 $20,318
=====================
Deferred income taxes were classified in the accompanying balance sheets at
September 30, 2000 and 1999 as follows (in thousands):
2000 1999
-------------------------------------------------------------------------------
Current $ (446) $ (8)
Long-term 20,725 20,326
------------------------
Total $20,279 $20,318
========================
The components of federal and state income taxes reflected in the accompanying
statements of income for the years ended September 30, 2000, 1999 and 1998 were
as follows (in thousands):
2000 1999 1998
--------------------------------------------------------------------------------
Federal:
Current $2,268 $ (630) $2,702
Deferred (400) 2,996 (268)
Investment tax credits (123) (123) (124)
--------------------------------------
Total federal 1,745 2,243 2,310
--------------------------------------
State:
Current 497 (276) 555
Deferred (95) 773 (53)
--------------------------------------
Total state 402 497 502
--------------------------------------
Total provision for income taxes $2,147 $2,740 $2,812
======================================
23
<PAGE>
The Company's effective income tax rate was 73%, 41.7% and 36.4% for the years
ended September 30, 2000, 1999 and 1998, respectively. The significant increase
in the effective federal and state income tax rate is due to merger related
costs that are not tax deductible. The following table reconciles the income tax
provision calculated using the federal statutory tax rate of 34% to the book
provision for federal and state income taxes (in thousands):
2000 1999 1998
-------------------------------------------------------------------------------
Tax calculated at statutory rate $1,001 $2,234 $2,627
Increase (reduction) in effective tax
resulting from:
Amortization of investment tax credit (123) (123) (124)
Adjustment due to change in tax rates (28) (28) (28)
State taxes, net of federal tax benefit 265 328 331
Merger-related costs 978 - -
Other, net 54 329 6
--------------------------------
Total provision for income taxes $2,147 $2,740 $2,812
================================
Note 7. Employee Benefit Plans
Retiree Benefits
----------------
The Company has noncontributory defined benefit plans covering substantially all
employees. Benefits are based on years of credited service and average earnings
during the five highest consecutive years prior to the normal retirement date.
The Company is also charged for pension expense for the management pension plan
of the parent company.
The Company's funding policy is to annually contribute to the plans 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.
In addition to providing pension benefits, the Company provides certain health
care and life insurance benefits to qualified retired employees.
The expense recorded in fiscal 2000, 1999 and 1998 for providing post-retirement
benefits, including amortization of the accumulated projected benefit obligation
over a 20-year period, was $177,000, $173,000 and $230,000, respectively.
24
<PAGE>
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.
<TABLE>
<CAPTION>
(In thousands) Pension Medical and life
------------------------------------------------
For the years ended September 30, 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year $ 8,228 $8,425 $2,453 $2,439
Service cost 254 274 48 52
Interest cost 602 576 178 167
Participant contributions - - - -
Plan amendments - - - -
Curtailment (gain) or loss 38 - 100 -
Special termination benefits 23 - - -
Benefits paid (364) (452) (185) (146)
Actuarial (gain) or loss (303) (595) 8 (59)
------------------------------------------------
Benefit obligation at end of year $ 8,478 $8,228 $2,602 $2,453
================================================
Change in plan assets:
Fair value of plan assets at beginning of year $ 9,835 $9,167 $1,369 $1,248
Actual return on plan assets 582 898 93 80
Employer contributions 183 222 176 187
Participant contributions - - - -
Special termination benefits paid (94) - - -
Benefits paid (363) (452) (185) (146)
------------------------------------------------
Fair value of plan assets at end of year $10,143 $9,835 $1,453 $1,369
================================================
</TABLE>
25
<PAGE>
<TABLE>
<CAPTION>
(In thousands) Pension Medical and life
------------------------------------------------------------
For the years ended September 30, 2000 1999 2000 1999
-------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Reconciliation of funded status:
Funded status $1,666 $1,607 $(1,149) $(1,084)
Contributions between 7/31 and 9/30 - - 44 43
Unrecognized actuarial (gain) or loss (238) (294) (715) (919)
Unrecognized transition (asset) or obligation (145) (205) 1,475 1,961
Unrecognized prior service cost 105 183 - -
------------------------------------------------------------
Net amount recognized at year end $1,388 $1,291 $ (345) $ 1
============================================================
Additional year-end information for plans
with benefit obligations in excess of plan assets:
Benefit obligation $ - $ - $ 2,602 $ 2,453
Fair value of plan assets $ - $ - $ 1,453 $ 1,369
Components of net periodic benefit cost:
Service cost $ 254 $ 274 $ 48 $ 52
Interest cost 602 576 178 167
Expected return on plan assets (904) (827) (131) (124)
Amortization of prior service cost 56 56 - -
Amortization of transitional (asset) or Obligation (60) (60) 140 140
Recognized actuarial (gain) or loss - - (58) (62)
------------------------------------------------------------
Net periodic benefit cost $ (52) $ 19 $ 177 $ 173
============================================================
Additional FAS No. 88 charge recognized due to:
Curtailment $ 22 $ - $ 346 $ -
Settlement $ - $ - $ - $ -
Special termination benefits $ 117 $ - $ - $ -
Weighted-average assumptions:
Discount rate 7.75% 7.50% 7.75% 7.50%
Expected long-term rate of return on plan 9.50% 9.50% 9.50% 9.50%
Assets
Rate of compensation increase 4.00% 4.00% 4.00% 4.00%
</TABLE>
The tables above reflect special termination benefits and the effects of a
curtailment charge. These costs have been recorded as reorganization cost in the
income statement. The prior service cost is amortized on a straight-line basis
over the average remaining service period for active participants. The gain or
loss in excess of the greater of 10% of the benefit obligation or the market
value of assets is amortized on a straight-line basis over the average remaining
service period for active participants.
26
<PAGE>
Assumed Health Care Cost Trend
------------------------------
For measurement purposes, an 8% annual rate of increase in the per capita cost
of covered health care benefits was assumed for pre-65 coverage. The rate is
assumed to decrease to 5% for 2002 and remain at that level thereafter. For age
post-65, a 10% the annual rate of increase was assumed, decreasing to 5% for
2004 and thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. A one-percentage-point change in assumed
health care costs trend rates would have the following effects for 2000:
<TABLE>
<CAPTION>
One-percentage- One-percentage-
point increase point decrease
----------------------------------------
<S> <C> <C>
Service and interest cost components $ 9,743 $ (9,032)
Post-retirement benefit obligation 106,712 (99,517)
</TABLE>
Savings Plans
-------------
The Company has employee 401(k) savings and investment plans covering
substantially all employees. The Company made contributions of $97,000, $76,000
and $87,000 for the years ended September 30, 2000, 1999 and 1998, respectively.
Note 8. Operating Leases
The Company leases certain facilities and equipment under long-term,
noncancelable operating lease agreements having terms greater than one year.
Future minimum rental commitments for these leases at September 30, 2000 are
approximated as follows (in thousands):
Fiscal year Amount
--------------------------------------------------------------------------------
2001 $203
2002 $192
2003 $173
2004 $167
2005 $ 99
The total rental expense charged to operations for the years ended September 30,
2000, 1999 and 1998 was approximately $606,000, $735,000 and $807,000,
respectively.
Note 9. Commitments and Contingencies
Contracts
---------
The Company has various contractual agreements covering the transportation of
natural gas, underground storage facilities and the purchase of natural gas,
which are recoverable under the Company's cost of gas rates. These contracts
expire at various times from 2000 to 2011.
27
<PAGE>
Litigation
----------
The Company has been named in certain lawsuits arising from normal operations.
In the opinion of management, the outcome of these lawsuits will not have a
material adverse effect on the financial position or results of operations of
the Company.
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 is participating with Public Service Company of New Hampshire (PSNH),
Northern Utilities and Central Vermont Public Service Company in the
investigation of a former manufactured gas site in Dover, New Hampshire. The
Company is participating with PSNH in the investigation of a former
manufacturing gas site in Nashua, New Hampshire, and has reached settlement with
PSNH on a site in Laconia, New Hampshire. The Company is also engaged in
remediation of a site in Concord, New Hampshire and investigation of a site in
Manchester, New Hampshire. Costs to complete the Company's share of site
investigation, risk characterization and remediation at manufacturing gas sites
are currently estimated to range from $2.1 million to $2.6 million. In addition
to costs incurred to date, the Company has recorded $2.1 million as a current
liability at September 30, 2000 with a corresponding charge to recoverable
environmental cost. The New Hampshire Public Utilities Commission has approved a
recovery mechanism for costs incurred at all former manufacturing gas sites,
except recovery for the Concord site, 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. The recovery mechanism for the Concord site provides for recovery from
customers, over a seven-year period, of substantially all costs, excluding
carrying cost.
Note 10. Merger
On July 14, 1999, ENI and Eastern Enterprises (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 has 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
28
<PAGE>
costs, and write-offs of $1.9 million for assets, principally software, which
were no longer used or useful.
29
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
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 a wholly-owned
subsidiary of EnergyNorth, Inc.) as of September 30, 2000 and 1999 and the
related statements of income, retained earnings and cash flows for each of the
three years in the period ended September 30, 2000. 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 financial position of EnergyNorth Natural Gas, Inc.
as of September 30, 2000 and 1999, and the results of its operations and its
cash flows for each of the three years in the period ended September 30, 2000,
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
Boston, Massachusetts
November 20, 2000
30
<PAGE>
(b) Supplementary Financial Information
Selected Quarterly Financial Data (Unaudited) EnergyNorth Natural Gas, Inc.
<TABLE>
<CAPTION>
Operating Operating Net income
(In thousands) revenues income (loss) (loss) Cash dividends
----------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First Quarter
2000 $24,658 $ 3,918 $ 2,956 $ 965
1999 22,019 3,984 2,992 934
----------------------------------------------------------------------------------
Second Quarter
2000 44,886 6,992 6,060 965
1999 36,441 7,040 6,118 934
----------------------------------------------------------------------------------
Third Quarter
2000 16,212 (1,115) (2,037) 965
1999 11,383 (877) (1,770) 976
----------------------------------------------------------------------------------
Fourth Quarter
2000 8,837 (5,139) (6,183) 1,289
1999 6,774 (1,507) (3,509) 976
----------------------------------------------------------------------------------
</TABLE>
Note: In the opinion of the Company, the quarterly financial data include all
adjustments, consisting of normal recurring adjustments and reclassifications,
necessary for a fair presentation of such information. Quarterly amounts vary
significantly due to seasonal weather conditions.
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
All 120,000 shares of the Company's outstanding common stock are held by ENI.
31
<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not Required.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K
(a) List of documents filed as part of this Report
(1) Financial Statements
The following financial statements are included herein under Part II,
Item 8:
<TABLE>
<CAPTION>
Page No(s).
in this Report
--------------
<S> <C>
Statements of Income for the years ended September 30, 2000, 1999 and 1998............................. 13
Balance Sheets at September 30, 2000 and 1999.......................................................... 14
Statements of Capitalization at September 30, 2000 and 1999............................................ 15
Statements of Retained Earnings for the years ended September 30, 2000, 1999 and 1998.................. 16
Statements of Cash Flows for the years ended September 30, 2000, 1999 and 1998......................... 17
Notes to Financial Statements.......................................................................... 18-29
Report of Independent Public Accountants............................................................... 30
Supplementary Financial Information.................................................................... 31
</TABLE>
(2) Financial Statement Schedules
The following supplementary financial statement schedules required by Rule
5-04 of Regulation S-X, and report thereon, are filed as part of this Form
10-K on the page indicated below:
<TABLE>
<CAPTION>
Schedule Page No. in
Number Description this Report
------ ----------- ----------
<S> <C> <C>
II Valuation and Qualifying Accounts for the three years ended September 30, 2000................ 34
Report of Independent Public Accountants...................................................... 30
</TABLE>
32
<PAGE>
Schedules other than the one listed above are either not required or
not applicable, or the required information is shown in the financial
statements or notes thereto.
(3) Exhibits Required by Item 601 of Regulation S-K
See Exhibit Index on pages 36 and 37.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended September 30,
2000.
(c) Exhibits - See Exhibit Index on pages 36 and 37.
(d) Financial Statement Schedules
33
<PAGE>
SCHEDULE II
ENERGYNORTH NATURAL GAS, INC.
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Reserves that are deducted in the balance sheets from assets to which they
apply:
<TABLE>
<CAPTION>
Additions
-----------------------------
Balance Balance
at Charged to Charged to at end
Year ended beginning costs and other of
September 30, Description of period expenses accounts/(1)/ Deductions period
--------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2000 Allowance for
doubtful $1,069 $1,276 $118 $1,586 $ 877
accounts
1999 Allowance for
doubtful 1,088 880 167 1,066 1,069
accounts
1998 Allowance for
doubtful 1,309 1,080 118 1,419 1,088
accounts
</TABLE>
_____________________
/(1)/ Represents recoveries on accounts previously written off.
34
<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.
Registrant
By: /s/ Joseph. F. Bodanza
--------------------------------------------
Joseph F. Bodanza
Senior Vice President
Finance, Accounting and Regulatory Affairs
(Principal Financial and Accounting Officer)
Dated: December 29, 2000
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 29 day of December, 2000.
Signature Title
--------- -----
CHESTER R. MESSER Director and President
-------------------------------
CHESTER R. MESSER
35
<PAGE>
EXHIBIT INDEX
The exhibits listed below are filed herewith, or are incorporated herein by
reference to other filings.
Exhibit
Number Description
------ -----------
2.0 Agreement and Plan of Reorganization dated July 14, 1999 among Eastern
Enterprises, EE Acquisition Company, and EnergyNorth, Inc. is
incorporated by reference to 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 is incorporated by reference to 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. are
incorporated by reference to 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, are incorporated
by reference to 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, is incorporated by reference
to 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, is incorporated by reference to 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, is incorporated by reference to 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, is
36
<PAGE>
incorporated by reference to 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, is incorporated by reference to 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. is incorporated by reference to 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. is incorporated by reference to Exhibit 10.2 to
EnergyNorth, Inc.'s Form 10-K (File No. 0-11035) for the fiscal year
ended September 30, 1995.
10.3 Contract Restructuring Letter Agreement between Tennessee Gas Pipeline
Company and EnergyNorth Natural Gas, Inc. effective November 1, 1999
is incorporated by reference to 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, is incorporated by
reference to 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, is
incorporated by reference to 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.
27 Financial Data Schedule of the Registrant.
37
