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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-1004
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, 1995
COMMISSION FILE NUMBER 1-7479
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BAY STATE GAS COMPANY
(Exact name of registrant as specified in its charter)
MASSACHUSETTS 04-2548120
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
300 FRIBERG PARKWAY, WESTBOROUGH, MASSACHUSETTS 01581-5039 (508/836-7000)
(Address and telephone number of principal executive offices)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, $3.33 1/3 par value New York Stock Exchange
Boston Stock Exchange
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. [ ]
Aggregate market value of registrant's voting stock held by non-affiliates
as of November 15, 1995 was $332,038,791*.
On November 15, 1995, the Company had 13,357,394 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
DOCUMENTS PART OF FORM 10-K
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Portions of the Proxy Statement for the Annual Meeting of Common
Shareholders to be held on January 25, 1996............................ Part III
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* Calculated by excluding all shares held by directors and executive officers of
Registrant, without conceding that all such persons are "affiliates" of the
Registrant for purposes of the Federal securities laws.
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TABLE OF CONTENTS
PART I PAGE
----
Item 1. Business:
The Company............................................................. 3
Local Transportation Markets and Competition............................ 3
Natural Gas Sales....................................................... 4
Capacity Requirements................................................... 4
Regulation and Rates.................................................... 5
Franchises.............................................................. 6
Other Energy Products and Services...................................... 6
Energy Ventures......................................................... 6
Employees............................................................... 6
Executive Officers of the Registrant.................................... 6
Item 2. Properties.............................................................. 7
Item 3. Legal Proceedings....................................................... 7
Item 4. Submission of Matters to a Vote of Security Holders..................... 7
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters................................................................. 8
Item 6. Selected Financial Data................................................. 8
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 8
Item 8. Financial Statements and Supplementary Data............................. 14
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 30
PART III
Item 10. Directors and Executive Officers of the Registrant...................... 30
Item 11. Executive Compensation.................................................. 30
Item 12. Security Ownership of Certain Beneficial Owners and Management..........
Item 13. Certain Relationships and Related Transactions.......................... 30
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 31
Signatures.............................................................. 33
Exhibit Index........................................................... 34
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PART I.
ITEM 1. BUSINESS
THE COMPANY
Bay State Gas Company ("Bay State" or the "Company") was incorporated in
1974 as a Massachusetts corporation. However, Bay State's predecessor companies'
operations began in 1847, and consecutive quarterly dividends have been paid by
these entities or Bay State since 1853. The Company is primarily a gas
distribution utility that provides local transportation service in the Brockton,
Lawrence, and Springfield, Massachusetts areas. Additionally, the Company also
offers additional energy products and services to its customers, including
commodity sales of natural gas, and invests in energy ventures. Approximately
95% of all revenues are generated from providing local transportation and
natural gas sales with 84% of these annual revenues coming from the Company's
Massachusetts service area. Bay State has five subsidiaries within its corporate
organization. Northern Utilities, Inc. ("Northern") is a gas distribution
utility operating in the Portland and Lewiston areas in Maine and the Portsmouth
area in New Hampshire. Granite State Gas Transmission, Inc. ("Granite") is an
interstate gas transmission and supply company operating in the states of Maine,
New Hampshire, Massachusetts, and Vermont. Granite has four wholly owned
subsidiaries, Bay State Energy Development, Inc., which owns an equity interest
in the MASSPOWER cogeneration partnership, Natural Gas Development Corp., a
corporation established to invest in the Portland Natural Gas Transmission
System ("PNGTS"), a proposed natural gas transmission pipeline in northern New
England, Bay State Energy Enterprises, Inc., which owns a equity interest in KBC
Energy Services, a partnership which markets natural gas supplies and
energy-related services on a nonregulated basis to commercial and industrial
end-users and Energy Asset Funding Inc., a corporation established to provide
financing for energy-related equipment.
Natural gas sales in New England are seasonal, and the Company's results of
operations reflect this seasonality. Accordingly, results of operations are
typically most favorable in the second quarter of the Company's fiscal year
(three months ended March 31), with results of operations being next most
favorable in the first quarter, while losses are commonly incurred in the third
and fourth quarters. The quarterly operating results for 1995 and 1994 are
described further in Note 9 of "Notes to Consolidated Financial Statements,"
Part II, Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Company's customers generally are billed monthly on a cycle basis in
therms. One therm equals 100,000 British thermal units (1 Btu), the heat content
of approximately 100 cubic feet of gas. 1,000,000 Btu (1 MMBtu), or ten therms
are the energy equivalent of approximately 1,000 cubic feet of natural gas or
7.14 gallons of home heating oil.
LOCAL TRANSPORTATION MARKETS AND COMPETITION
In 1995, 97% of Bay State's customers purchased bundled local
transportation and natural gas and the remaining 3% elected to purchase
unbundled local transportation. The tables below show the net change in
transportation customers and throughput volumes for the past three years.
TABLE 1 -- NET LOCAL TRANSPORTATION CUSTOMER GROWTH
Yearly Increase in Number of Customers
1995 1994 1993
------ ------ ------
Residential......................................... 5,161 4,015 4,954
Commercial and Industrial........................... 1,256 800 852
Unbundled transportation............................ 76 9 --
----- ----- -----
Net increase in number of customers................. 6,493 4,824 5,806
===== ===== =====
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TABLE 2 -- CHANGE IN THROUGHPUT VOLUMES
Yearly Increase (Decrease) -- Thousands of MMBtu*
1995 1994 1993
------ ------ ------
Residential........................................ (2,727) 848 1,144
Commercial and industrial.......................... (2,696) 1,150 1,395
Sales to other utilities........................... 1,569 1 (402)
Interruptible and other............................ 8,128 (766) (2,923)
Unbundled transportation........................... 1,923 12,222 2,619
------ ------ ------
Total increase in throughput....................... 6,197 13,455 1,833
====== ====== ======
<FN>
- ---------------
* Volumes have not been normalized for weather variations.
The Company's principal competitors are unregulated fuel-oil retailers and
regulated electric utilities. Increases in demand for natural gas are primarily
driven by the rate of economic growth and new construction within the Company's
service territories, and by the marketing and pricing of competing fuels.
In the residential market, the Company should continue to benefit from the
New England region's market and growth potential. There are approximately
150,000 households along the Company's mains and additional homes located short
distances from existing gas mains that use no gas at all. In addition, the
Company anticipates additional growth from the estimated 44,000 existing
residential nonheating customers. These are attractive markets for the Company
and represent an opportunity to increase gas sales with little or no capital
investment.
For commercial and industrial customers, environmental issues are an
important issue in choosing an energy source. Since natural gas is the cleanest
burning fossil fuel, using natural gas can assist companies in complying with
the Clean Air Act and underground oil storage tank legislation.
Finally, the Company markets gas to large users on a seasonal or
interruptible basis. Approximately 59% of these interruptible volumes in 1995
were sold to five electric utilities for electric power generation. The
remainder were sold to approximately 110 industrial customers equipped to burn
either natural gas or fuel oil. Price is the key competitive factor in this
market, and the Company pursues interruptible sales through a flexible pricing
structure designed to remain competitive with other fuels. Substantially all net
margins from interruptible sales are passed back to firm customers through cost
of gas adjustment clauses (see "Rates and Regulations").
NATURAL GAS SALES
The natural gas sales portion of the Company's bundled service does not
currently provide a profit margin. However, as all but 85 of the Company's
287,000 local transportation customers purchase bundled transportation and
natural gas, minimizing gas costs is an important part of the Company's
business.
The Company's strategy of balancing gas purchase costs and security of
supply is achieved by optimizing the mix and terms of natural gas contracts with
the use of supplemental liquefied natural gas and propane to meet peak winter
demand. The Company maintains a diversified gas supply portfolio of domestic and
Canadian gas supply contracts with producers.
CAPACITY REQUIREMENTS
Bay State has capacity contracts for the transmission of natural gas to its
distribution system from the producing areas of North America. The Company
currently transports natural gas from Canada through a converted oil pipeline
leased from the Portland Pipe Line Corporation ("PPLC"). The PPLC lease
currently extends to March 31, 1997. An agreement with PPLC to extend the lease
through the 1997-1998 heating season is being sought. Short-term contingency
plans have been developed for supplying customers in Maine and New Hampshire
through the 1997-1998 heating season in the event that the lease is not
extended. Long-term, two projects to replace the pipeline capacity provided by
the PPLC lease are being pursued, a 2.0 million MMBtu liquefied natural gas
storage facility in Wells, Maine, and PNGTS. For further discussion of these
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projects see Note 8 of "Notes to Consolidated Financial Statements," Part II,
Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REGULATION AND RATES
The Company and its subsidiaries, are subject, where applicable, to
regulation by the Massachusetts Department of Public Utilities ("MADPU"), the
New Hampshire Public Utilities Commission ("NHPUC"), the Maine Public Utilities
Commission ("MPUC") and the Federal Energy Regulatory Commission ("FERC") with
respect to rates, adequacy of service, issuance of securities, accounting, and
other matters.
The tariff schedules of the local distribution companies provide for
declining block rates which result in reductions in the unit price as usage
increases, and for seasonal rates that charge customers more per unit for gas
purchased during the high-demand winter heating season and less per unit during
summer months. These schedules also contain cost of gas adjustment ("CGA")
clauses that permit the distribution companies to pass on to firm customers
increases or decreases in recovered natural gas costs. Substantially all gas
supplier refunds and profits from interruptible sales are returned to firm
customers through the CGA clauses.
As a result of a third party fuel inventory financing program instituted by
the Company in 1982, fuel inventory and the related administrative and carrying
costs are also recovered through the CGA clauses. In addition, the MADPU allows
recovery of the following through the CGA: 1) the working capital costs
associated with purchased gas costs; 2) clean-up costs associated with waste
materials from former gas manufacturing sites; and 3) costs associated with
MDPU-approved energy conservation and load management programs.
The Company offers special contracts to large volume industrial customers
in its Massachusetts service area and natural gas transportation service to
industrial end-user customers in both its Massachusetts and New Hampshire
jurisdictions. Contracts for such service are individually filed with and
approved by the MADPU and NHPUC and are in effect for specified periods of time.
The following table provides the most recent rate activity of the Company
by state and federal jurisdictions:
TABLE 4 -- RATE ACTIVITY
REQUESTED INCREASES GRANTED INCREASE
--------------------------- -----------------------------------------
RETURN ON RETURN ON
DATE AMOUNT COMMON AMOUNT COMMON DATE
JURISDICTION FILED (IN MILLIONS) EQUITY (IN MILLIONS) EQUITY EFFECTIVE
- ------------ -------- ------------- --------- ------------- --------- ---------
NHPUC.................... 9/15/95 $ .3 (a) $ .3 (a) 11/1/95
MADPU.................... 4/14/95 $ .0 (b) (b) (b) (b)
NHPUC.................... 9/14/94 $ .1 (a) $ .1 (a) 11/1/94
FERC..................... 4/29/94 $ 1.6 14.20% $ 1.1 11.50% 11/1/94
NHPUC.................... 9/20/93 $ .3 (a) $ .3 (a) 11/1/93
NHPUC.................... 9/21/92 $ .6 (a) $ 0.5 (a) 11/1/92
MADPU.................... 4/16/92 $20.6 13.00% $11.5 11.40% 11/1/92
NHPUC.................... 7/18/91 $ 2.5 13.95% $ 1.3 (c) 9/30/91
FERC..................... 5/31/91 $ .9 15.75% $ .4 (c) 7/1/92
<FN>
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(a) The revenue increase was granted under a step adjustment filing allowing
recovery of certain costs under the terms of the Settlement Agreement
effective 9/30/91; no return was requested or ordered.
(b) An overall revenue-neutral rate redesign has been filed with the MADPU. The
goal of the rate redesign is to implement rates that more closely reflect
the actual costs associated with serving different customers. New rates are
expected to be effective early in calender 1996.
(c) The revenue increase was granted pursuant to a stipulation. No percentage
return on common equity related to the revenue increase was referenced in
the order.
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FRANCHISES
The utility franchise rights of the Company are non-exclusive. Competition
from other companies in the distribution of gas, however, is restricted without
prior approval of the applicable local and state governmental agencies.
The laws of the Commonwealth of Massachusetts permit a municipality, by
appropriate vote of its residents, to enter the gas business and purchase the
facilities of the utility serving such municipality. If the utility is not
willing to sell, the municipality may construct a plant or acquire one from
another source. The Company is not aware of any municipality which intends to
seek approval of such action.
OTHER ENERGY PRODUCTS AND SERVICES
For a discussion of Other Energy Products and Services see "Other Energy
Products and Services" in Part II, Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations.
ENERGY VENTURES
For a discussion of Income (Loss) from Investments in Energy Ventures, see
"Income (Loss) from Investments in Energy Ventures" in Part II, Item 7,
Management's Discussion and Analysis of Financial Condition and Results of
Operations.
EMPLOYEES
The Company employed 1,062 persons at September 30, 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, ages, and positions of the principal executive officers of the
Registrant as of November 15, 1995 are listed below along with their business
experience during the past five years. All principal executive officers are
elected annually by the Board of Directors at the Directors' first meeting
following the annual meeting of shareholders. There are no family relationships
among these officers, except as noted below, nor is there any arrangement or
understanding between any officer and any other person pursuant to which the
officer was selected.
NAME, AGE AND POSITION BUSINESS EXPERIENCE DURING PAST 5 YEARS
---------------------- ---------------------------------------
Roger A. Young, 49, President (Chief Executive
Officer)(a).................................... Director, President, and Chief Executive
Officer.
Joel L. Singer, 39, Executive Vice President
(Chief Operating Officer)...................... Director, Executive Vice President, and
Chief Operating Officer since 1995;
Director of Arthur D. Little Inc.'s North
American Natural Gas Practice, Cambridge,
MA, 1993 to 1995, Manager Natural Gas
Sales/Vice President Petrofino Gas
Pipeline, American Petrofino, Dallas, TX,
1989 to 1993.
Thomas W. Sherman, 55, Executive Vice President
(Chief Financial and Accounting Officer and
Treasurer)..................................... Director, Executive Vice President, and
Chief Financial Officer; Treasurer since
1994.
Dwight G. Curley, 58, Senior Vice President...... Senior Vice President since 1992; Vice
President 1990 to 1992.
James A. Burke, 56, Vice President............... Vice President.
John F. Doucette, 51, Vice President............. Vice President.
<FN>
- ---------------
(a) Charles H. Tenney II, Chairman of the Board of Directors, is the stepfather
of Roger A. Young, President and Chief Executive Officer.
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NAME, AGE AND POSITION BUSINESS EXPERIENCE DURING PAST 5 YEARS
---------------------- ---------------------------------------
Philip W. Kallaugher, 53, Vice President......... Vice President since 1993; Division
Manager of the Brockton division 1988 to
1992.
Thomas A. Sacco, 54, Vice President.............. Vice President.
James D. Simpson, 45, Vice President............. Vice President since 1993; Director of
Rates and Economic Analysis 1992 to 1993;
Director of Rates 1988 to 1992.
John R. Snow, 54, Vice President................. Vice President.
Stephen J. Curran, 49, Controller................ Controller.
ITEM 2. PROPERTIES
The Company holds franchise rights to lay gas mains in the streets and
public places of various service territories in Massachusetts, Maine, and New
Hampshire.
As of September 30, 1995, the Company's system consisted of approximately
5,306 miles of distribution mains; 132 miles of transmission lines, with
requisite accessory pumping and regulating stations; LNG liquefaction,
vaporization and storage facilities; propane storage tanks; 259,185 services
(small pipe connecting mains with piping on the customers' premises) and 287,213
meters installed on customers' premises.
The Company also leases a transmission line which is 166 miles in length
running from the Canadian border through Vermont and New Hampshire and
terminating in South Portland, Maine (see Item 1. Business, "Capacity
Requirements").
The transmission and distribution system is for the most part located on or
under public streets, alleys, avenues, and other public places or on private
property not owned by the Company, with the permission or consent of the
respective owners.
ITEM 3. LEGAL PROCEEDINGS
The Company is working with federal and state environmental agencies to
assess the extent and environmental impact of and appropriate remedial action
for waste materials from former gas manufacturing sites (see Note 8 of "Notes to
the Consolidated Financial Statements," Part II, Item 8, Financial Statements
and Supplementary Data).
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted during the fourth quarter of the fiscal
year covered by this report to a vote of security holders through solicitation
of proxies or otherwise.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
QUARTER ENDED
-----------------------------------------------------
FISCAL 1995 DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30
----------- ----------- -------- ------- ------------
High..................................... $25 1/8 $25 3/4 $25 1/2 $25 1/4
Low...................................... 22 1/2 22 1/4 23 1/8 22 7/8
FISCAL 1994
-----------
High..................................... $32 $28 3/8 $25 5/8 $25 3/8
Low...................................... 27 7/8 23 7/8 23 5/8 23 1/2
The common stock of the Company is listed on both the New York Stock
Exchange and the Boston Stock Exchange. The ticker symbol is "BGC" and common
listings in the financial press include "BayStGas" and "BaySGs." As of November
15, 1995, the Company had approximately 11,336 shareholders of record. The
number of shareholders indicated does not reflect the number of persons or
entities who hold their common stock in nominee name through various brokerage
firms or other entities. Information regarding cash dividends declared on common
stock is included in Note 9 of "Notes to the Consolidated Financial Statements,"
Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ITEM 6. SELECTED FINANCIAL DATA
Listed below is the required selected financial data for the Company's last
five fiscal years.
In thousands, except per share amounts 1995 1994 1993 1992 1991
- -------------------------------------- -------- -------- -------- -------- --------
Total operating revenues.............. $418,118 $463,280 $412,410 $372,859 $350,162
Income from continuing operations..... 23,128 24,485 22,807 18,363 15,817
Earnings per average common share from
continuing operations............... $ 1.71 $ 1.85 $ 1.75 $ 1.41 $ 1.32
Total assets.......................... 630,355 614,798 563,000 498,930 452,153
Long-term obligations under capital
leases.............................. 1,611 2,719 3,747 4,700 5,585
Capitalization:
Common equity....................... 219,873 215,389 200,088 187,032 146,042
Preferred sock...................... 5,149 5,293 5,392 20,512 20,677
Long-term debt...................... 199,000 191,000 176,000 116,139 131,775
Cash dividends declared per common
share............................... $ 1.48 $ 1.44 $ 1.40 $ 1.36 $ 1.31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
Year In Review
During 1995, Bay State Gas Company ("Bay State" or the "Company") continued
to respond to the changing energy industry while experiencing warmer than normal
weather. During 1995, the weather was 11% warmer than the prior year and 6%
warmer than normal within the Company's service territories. The following table
displays the degree days for the past three years:
PERCENTAGE
DEGREE COLDER/(WARMER)
YEAR DAYS THAN NORMAL
---- ------- ----------------
1995............................................... 6,589 (6.4)%
1994............................................... 7,366 5.2 %
1993............................................... 7,180 2.7 %
Bay State responded to the warmer weather by implementing several cost
saving and service-related program improvements that not only minimized the
impact of the weather on net income for 1995, but will also positively impact
earnings in future years.
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Net income was $23.1 million in 1995 compared to $24.5 million in 1994, and
earnings per share were $1.71. This compares to $1.85 one year ago. The common
stock dividends declared in 1995 were $1.48 per share, 2.8% higher than the
prior year. This was the twelfth consecutive year of increased common stock
dividends, and it completes the 142nd year of consecutive quarterly dividends.
The current annualized dividend is equivalent to $1.50 per share.
Local Transportation
The following table details the components of local transportation revenues
for the past three years:
In millions 1995 1994 1993
----------- ------ ------ ------
Bundled revenues....................................... $156.3 $164.0 $157.3
Unbundled revenues..................................... 4.3 2.5 .4
------ ------ ------
Total.................................................. $160.6 $166.5 $157.7
====== ====== ======
The majority of Bay State's customers purchase bundled local transportation
and natural gas. Some larger commercial and industrial customers have elected to
purchase unbundled local transportation, requiring them to now manage their own
gas purchasing, balancing, and storage functions.
Local transportation revenues decreased 3.6% from 1994 to 1995. This
decrease in revenues was primarily attributable to the warmer weather
experienced in the Company's service territories during 1995, which reduced
transportation, or throughput, to firm customers. The 11% change in weather from
year to year would have resulted in a $7.1 million decrease in transportation
revenues. However, the Company added almost 6,500 customers in 1995, up from
4,800 and 5,800 in 1994 and 1993, respectively. This 2.3% growth in the customer
base somewhat offset the negative impact of the weather on revenues.
Additionally, total system throughput increased from 77.8 million MMBtu in
1994 to 84.0 million MMBtu in 1995 as the Company utilized its capacity during
the warmer weather by supplying additional volumes to interruptible customers.
The profit margins from these customers are passed back to the Company's firm
customers through reduced gas costs.
Natural Gas Sales
The natural gas sales portion of the Company's bundled service does not
currently provide a profit margin. However, as all but 85 of the Company's
287,000 local transportation customers purchase bundled local transportation and
natural gas, minimizing gas costs is an important part of the Company's
business.
The Company's strategy of balancing gas costs and security of supply is
achieved by optimizing the mix and terms of natural gas contracts with the use
of supplemental liquefied natural gas and propane to meet peak winter demand.
The Company maintains a diversified gas supply portfolio of domestic and
Canadian gas supply contracts with producers.
The Company's rates include cost of gas adjustment clauses ("CGA") pursuant
to which natural gas purchase costs and other costs are recovered from
customers. The following table details these costs:
In millions 1995 1994 1993
----------- ------ ------ ------
Gas demand................................................ $ 45.0 $ 33.7 $ 61.7
Gas commodity............................................. 112.5 138.8 149.1
------ ------ ------
Total purchase costs................................. 157.5 172.5 210.8
------ ------ ------
Transmission costs........................................ 53.9 58.5 1.8
Supplemental fuels........................................ 14.5 26.1 17.1
DSM & environmental programs.............................. 6.7 11.4 3.0
Transition costs.......................................... 2.7 8.4 2.7
------ ------ ------
Total..................................................... $235.3 $276.9 $235.4
====== ====== ======
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Recovered natural gas costs decreased by 15%, or $41.6 million, in 1995.
This decrease was the result of a decline in purchase costs combined with
decreases in supplemental fuel costs, demand-side management program ("DSM")
costs, and transition costs. The decrease in purchase costs reflect a
combination of the effect of the new competitive gas supply environment and the
impact of the warm weather on demand. The decrease in supplemental fuel costs
also reflect the warmer weather, as well as renegotiated contracts with
supplemental fuel suppliers. DSM programs are aimed at motivating customers to
use natural gas responsibly and, at the same time, cost the Company less than
the incremental gas supply these customers would have used otherwise. As these
programs have become fully implemented, their costs to customers have been
reduced.
The Federal Energy Regulatory Commission ("FERC") is permitting gas
pipeline companies, including those from which the Company purchases a
significant portion of its natural gas supplies and storage services, to bill
their customers for prudently incurred costs of transitioning into the
deregulated environment. These costs significantly declined in 1995 and should
continue to decline in the future. The Company has regulatory approval to
recover these costs through the CGA.
Other Energy Products and Services
Revenues from other energy products and services include the following:
In thousands 1995 1994 1993
------------ ------- ------- -------
Propane................................................ $ 7,603 $ 7,110 $ 6,762
Equipment rentals...................................... 6,976 6,265 5,877
Equipment service...................................... 5,447 3,984 3,683
Liquefaction........................................... 1,017 1,181 974
Other.................................................. 1,244 1,306 2,010
------- ------- -------
Total.................................................. $22,287 $19,846 $19,306
======= ======= =======
As is the case with revenues generated from local transportation, propane
revenues are also significantly impacted by the weather. However, in 1995, the
Company was able to expand its propane business to compensate for the
weather-related decrease in demand. Sales volumes for propane increased from 6.8
million gallons in 1994 to 7.4 million gallons in 1995.
Revenues from equipment rentals and service increased by over 21% or $2.2
million in 1995 after increasing by 7% and 4% in 1994 and 1993, respectively.
This significant increase in 1995 is primarily the result of moderate price
increases and new service offerings combined with an increase in the number of
units rented and serviced.
Operating Expenses
Operations expenses decreased by $3.9 million in 1995 after decreasing by
$1.5 million in 1994 and increasing by $7.5 million in 1993. As the result of
lower accounts receivable balances and improved collections from customers
through special payment arrangements, bad debt expense was reduced by $2.5
million in 1995. The remaining decrease reflects other cost control measures.
Higher plant balances, an outcome of customer growth, have resulted in
continuing increases in depreciation expense. Taxes, other than income taxes,
increased primarily due to higher property taxes. Annual increases in property
tax rates and assessments, combined with the growth in plant, increased property
taxes by $601,000, $808,000, and $821,000 in 1995, 1994, and 1993, respectively.
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Income (Loss) from Investments in Energy Ventures
The following table details the components of income (loss) from investments in energy
ventures for the past three years:
In thousands 1995 1994 1993
------------ ---- ----- -----
MASSPOWER............................................ $296 $(813) $(431)
KBC.................................................. (44) -- --
---- ----- -----
Total................................................ $252 $(813) $(431)
==== ===== =====
Bay State has operating results from two investments in energy ventures:
MASSPOWER, a cogeneration facility, and KBC Energy Services ("KBC"), a
partnership with Connecticut Natural Gas Corporation and Koch Gas Services
Company, which markets natural gas supplies and energy-related services on a
nonregulated basis to commercial and industrial end-users.
Interest Expense and Dividend Requirements on Preferred Stock
In 1995, the Company incurred additional interest expense due to
overcollections of recovered natural gas costs, a result of lower than
forecasted wellhead costs, and higher than anticipated pipeline supplier
refunds. Dividend requirements on preferred stock were relatively flat for the
comparative periods.
Results of Operations, 1994 and 1993
Net income increased $1.7 million and $4.4 million in 1994 and 1993,
respectively. In both years the Company experienced colder than normal weather
and had a growing customer base. The 1993 net income increase also reflected the
result of a rate increase in the Company's Massachusetts service area.
Operating revenues for 1994 and 1993 increased by $50.9 million and $39.6
million, respectively. In both years, this growth was primarily due to customer
additions, combined with an increase in the cost of gas and the colder weather.
The increase in 1993 operating revenues also reflected the Massachusetts rate
increase, which was effective in November 1992. Recovered natural gas costs
increased 17.6% and 9.3% in 1994 and 1993, respectively. The 1994 increase was
the result of higher combined purchase and transmission costs, and additional
increases in supplemental fuel costs, DSM program costs, and transition costs
while the 1993 increase was primarily the result of higher natural gas commodity
prices both under long-term contracts and from the spot market. These costs
represent a bundled product and transmission cost for most of 1993.
Operations expenses decreased by $1.5 million in 1994, after increasing by
$7.5 million in 1993. The decrease was the net result of the absence of costs
related to the union work stoppages, which occurred in 1993, and higher bad debt
expense related to the colder winter weather experienced in 1994. Also
contributing to the decrease in 1994 operations expenses was the effect of an
internal review of operations and corporate structure performed early in 1994.
This review resulted in a flatter, more efficient organization requiring almost
5% fewer employees. The largest increases in operating expenses in 1993 were in
employee benefits and outside services. The higher employee benefit expenses in
1993 included an increase in postretirement benefit costs, resulting from the
implementation of Statement of Financial Accounting Standards No. 106, and the
establishment of an accrual for an employee severance plan. Outside services
included an abnormal level of costs related to the union work stoppages and
regulatory restructuring costs.
Interest expense increased $2.2 million in 1994 due to higher levels of
long-term debt outstanding during the year, higher short-term debt rates, and a
decrease in the debt portion of AFUDC. Total interest expense for 1993 was
comparable to the prior year.
Liquidity and Capital Resources
Natural gas sales in New England are seasonal, and the Company's cash flows
reflect this seasonality. Approximately 74% of annual revenues are generated
during the heating season, which results in a high level of cash flow from
operations from late winter through early summer. Short-term borrowings are
typically highest in the fall and early winter as a result of completion of the
annual construction program and seasonal
11
12
working capital requirements. The Company has been able to access the financial
markets to meet its capital requirements and does not anticipate a change in its
access to, or the availability of, capital in the coming year.
Cash flows from operating activities
In millions 1995 1994 1993
----------- ------ ------ ------
Net cash provided by operating activities........ $ 73.7 $ 66.1 $ 15.6
Cash flows from operations improved by $7.6 million in 1995 despite a
decrease in net income primarily as the result of decreasing accounts receivable
balances, increases in refunds due customers, and lower cash contributions to
benefit plans. Refunds from upstream pipelines totaled approximately $15.8
million in 1995 as compared to $9.4 million in 1994. This amount will be
refunded to customers in the near future, contributing to reduced gas prices.
The Company made cash contributions to its benefit plans of $3.2 million, $15.3
million, and $15.0 million in 1995, 1994, and 1993, respectively.
Cash flows from investing activities
In millions 1995 1994 1993
----------- ------ ------ ------
Net cash used in investing activities............ $(57.9) $(52.2) $(51.4)
The Company invests in property, plant, and equipment to improve and
protect its distribution system, and to expand its system to meet customer
demand. As a result of planned spending, capital expenditures for property,
plant, and equipment increased $2.1 million in 1995. Capital expenditures for
1996 are estimated to be approximately $53.0 million.
The remaining increase in investing activities for 1995 relates to
expenditures on energy ventures. These expenditures were $4.6 million, $1.0
million, and $4.8 million in 1995, 1994, and 1993, respectively. In 1993, a
one-time equity investment was made in MASSPOWER of $4.2 million. Capital
expenditures for energy ventures for 1996 are estimated to be approximately $6.3
million (see note 8).
Cash flows from financing activities
In millions 1995 1994 1993
----------- ------ ------ ------
Net cash provided by (used in) financing
activities..................................... $(17.0) $(11.2) $ 35.8
As was the case in 1994, the 1995 decline in cash flows from financing
activities reflects a reduction in debt issuances as a result of strong cash
flows from operations. The Company has a shelf registration statement covering
up to $125.0 million of senior unsecured debt securities, under which $65.0
million in notes has been issued as of September 30, 1995. The Company has
access to $77.0 million in bank lines of credit. In early 1995, the Dividend
Reinvestment Plan was converted to a market purchase plan, eliminating new
equity issuances under this plan.
The Company is in the final stages of completing a sale and lease-back
arrangement for equipment rental assets with a financing company, through which
approximately $20.7 of additional capital will be made available. This, along
with continuing strong operating cash flows, will enable the Company to fund its
operating and investing activities without extensive long-term debt or equity
issuances in 1996.
Impact of Inflation
The rates charged to transportation customers may not be increased without
formal proceedings before regulatory authorities. Accordingly, in the absence of
authorized rate increases and except for changes in recovered gas costs, which
are reflected in customer rates, the Company must look to performance
improvements and higher sales volumes, particularly from highly profitable
market segments, to offset inflationary increases in its costs of operations.
Current rates only permit the Company to recover its historical cost of utility
plant and give no recognition to the current cost of replacing facilities.
Although no new material
12
13
rate proceedings are currently planned, under the current regulatory process,
management believes the cost of utility plant additions will be recognized in
setting future rate levels.
Environmental Issues
The Company continues to work with federal and state environmental agencies
to assess the extent and environmental impact of waste materials that exist at
or near former gas manufacturing sites located primarily in Massachusetts. The
costs of such assessments and any related remediation determined to be necessary
will be funded from traditional sources of capital and recovered from customers
(see note 8).
New Accounting Standard
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting
for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed
Of." This statement, which is effective for years beginning after December 15,
1995, requires the Company to review long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. The Company does not expect that the adoption of this
standard will have a material impact on the results of operations, financial
condition, or cash flows of the Company.
13
14
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BAY STATE GAS COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
YEARS ENDED SEPTEMBER 30, 1995, 1994, AND 1993, IN THOUSANDS EXCEPT PER SHARE
AMOUNTS
1995 1994 1993
-------- -------- --------
Operating revenues:
Local transportation..................................... $160,561 $166,534 $157,715
Energy products and services:
Natural gas sales...................................... 235,270 276,900 235,389
Other energy products and services..................... 22,287 19,846 19,306
-------- -------- --------
Total energy products and services............. 257,557 296,746 254,695
-------- -------- --------
Total operating revenues................................. 418,118 463,280.. 412,410
-------- -------- --------
Operating expenses:
Recovered natural gas costs............................ 235,270 276,900 235,389
Operations............................................. 84,076 88,005 89,455
Maintenance............................................ 8,545 8,744 8,525
Depreciation and amortization.......................... 26,026 24,209 21,562
Other taxes, principally property taxes................ 11,362 11,306 10,434
-------- -------- --------
Total operating expenses....................... 365,279 409,164 365,365
-------- -------- --------
Operating income......................................... 52,839 54,116 47,045
-------- -------- --------
Other income (expense):
Income (loss) from investments in energy ventures...... 252 (813) (431)
Interest income and other.............................. 1,630 1,980 2,830
Interest expense....................................... (17,018) (15,156) (12,910)
-------- -------- --------
Total other income (expense)................... (15,136) (13,989) (10,511)
-------- -------- --------
Income before income taxes............................... 37,703 40,127 36,534
-------- -------- --------
Federal and state taxes on income (note 2)............... 14,575 15,642 13,727
-------- -------- --------
Net income............................................... 23,128 24,485 22,807
Dividend requirements on preferred stock................. 299 309 562
-------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK...................... $ 22,829 $ 24,176 $ 22,245
======== ======== ========
Average number of common shares outstanding.............. 13,342 13,086 12,721
======== ======== ========
EARNINGS PER SHARE....................................... $ 1.71 $ 1.85 $ 1.75
======== ======== ========
DIVIDENDS DECLARED PER COMMON SHARE...................... $ 1.48 $ 1.44 $ 1.40
======== ======== ========
The accompanying notes are an integral part of these statements.
14
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BAY STATE GAS COMPANY
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 1995 AND 1994, IN THOUSANDS
1995 1994
-------- --------
ASSETS
Plant, at cost..................................................... $683,347 $636,601
Accumulated depreciation and amortization.......................... 184,942 166,229
-------- --------
Net plant.......................................................... 498,405 470,372
-------- --------
Investments in energy ventures (note 8)............................ 9,768 5,887
Prepaid benefit plans (note 7)..................................... 21,470 22,927
Other long-term assets............................................. 8,898 12,471
Current assets:
Cash and temporary cash investments.............................. 2,759 3,980
Accounts receivable, less allowances of $4,232 and $5,072........ 22,066 25,493
Unbilled revenues................................................ 3,747 3,661
Deferred gas costs............................................... 13,190 20,126
Inventories, at average cost (note 6)............................ 19,327 24,451
Other............................................................ 5,797 5,376
-------- --------
Total current assets..................................... 66,886 83,087
-------- --------
Regulatory assets:
Income taxes..................................................... 10,595 9,611
Other............................................................ 14,333 10,443
-------- --------
$630,355 $614,798
======== ========
CAPITALIZATION AND LIABILITIES
Capitalization (see accompanying statements and note 3):
Common stock equity.............................................. $219,873 $215,389
Preferred stock equity........................................... 5,149 5,293
Long-term debt................................................... 199,000 191,000
-------- --------
Total capitalization..................................... 424,022 411,682
-------- --------
Long-term liabilities:
Deferred taxes (note 2).......................................... 73,329 71,038
Other long-term liabilities...................................... 15,401 12,593
-------- --------
Total long-term liabilities.............................. 88,730 83,631
-------- --------
Commitments and contingencies (note 8)
Current liabilities:
Short-term debt (note 5)......................................... 31,500 37,750
Accounts payable................................................. 28,704 27,294
Fuel purchase commitments (note 6)............................... 15,801 20,820
Refunds due customers............................................ 28,928 23,372
Deferred and accrued taxes (note 2).............................. 4,677 2,492
Other............................................................ 7,993 7,757
-------- --------
Total current liabilities................................ 117,603 119,485
-------- --------
$630,355 $614,798
======== ========
The accompanying notes are an integral part of these statements.
15
16
BAY STATE GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
SEPTEMBER 30, 1995 AND 1994, IN THOUSANDS
1995 1994
-------------------- --------------------
AMOUNT PERCENT AMOUNT PERCENT
-------- ------- -------- -------
Common stock equity:
Common stock, $3.33 1/3 par value, authorized
36,000,000 shares; 13,353,394 and 13,290,491
shares outstanding........................... $ 44,511 $ 44,302
Paid-in capital................................. 100,339 99,145
Retained earnings............................... 75,023 71,942
-------- ----- -------- -----
Total common stock equity............... 219,873 51.9 215,389 52.3
-------- ----- -------- -----
Cumulative preferred stock; $100 par value,
authorized 200,000 shares; $50 par value,
authorized 150,000 shares
Non-redeemable:
$100 par value, 5% series; 16,862 shares
outstanding.................................. 1,686 1,686
$50 par value, 7.2% series; 17,710 shares
outstanding.................................. 886 886
-------- ----- -------- -----
Total non-redeemable.................... 2,572 .6 2,572 .6
-------- ----- -------- -----
Redeemable, $100 par value:
4.7% series; 11,127 and 11,742 shares
outstanding.................................. 1,113 1,174
Redeemable, $50 par value:
$3.80 series; 6,367 and 6,767 shares
outstanding.................................. 318 339
5 5/8% series; 5,761 and 6,523 shares
outstanding.................................. 288 326
$3.25 series; 17,164 and 17,646 shares
outstanding.................................. 858 882
-------- ----- -------- -----
Total redeemable........................ 2,577 .6 2,721 .7
-------- ----- -------- -----
Total cumulative preferred stock........ 5,149 1.2 5,293 1.3
-------- ----- -------- -----
Long-term debt:
Revolving Credit Agreement, due 1997............ 6,000 18,000
6.30% Notes, due 1998........................... 5,000 --
6.00% Notes, due 2000........................... 10,000 10,000
6.00% Notes, due 2001........................... 5,000 5,000
7.42% Notes, due 2001........................... 10,000 10,000
6.625% Notes, due 2002.......................... 5,000 --
7.25% Notes, due 2002........................... 20,000 20,000
7.37 - 7.55% Notes, due 2002.................... 28,000 28,000
6.00% Notes, due 2003........................... 15,000 15,000
6.58% Notes, due 2005........................... 10,000 10,000
6.93% Notes, due 2010........................... 10,000 --
9.20% Notes, due 2011........................... 10,000 10,000
9.28% Notes, due 2021........................... 5,000 5,000
8.15% Notes, due 2022........................... 12,000 12,000
7.625% Notes, due 2023.......................... 10,000 10,000
9.70% Notes, due 2031........................... 13,000 13,000
9.45% Notes, due 2031........................... 25,000 25,000
-------- ----- -------- -----
Total long-term debt.................... 199,000 46.9 191,000 46.4
-------- ----- -------- -----
TOTAL CAPITALIZATION.................... $424,022 100.0 $411,682 100.0
======== ===== ======== =====
The accompanying notes are an integral part of these statements.
16
17
BAY STATE GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 1995, 1994, AND 1993, IN THOUSANDS EXCEPT SHARE
AMOUNTS
CUMULATIVE
COMMON STOCK PREFERRED STOCK
--------------------------------------------- ------------------------
PAR PAID-IN RETAINED NON-
SHARES VALUE CAPITAL EARNINGS REDEEMABLE REDEEMABLE
---------- ------- -------- -------- ---------- ----------
BALANCE AT SEPTEMBER 30,
1992....................... 12,549,741 $41,832 $ 83,235 $ 61,965 $2,572 $ 17,940
Net income................... 22,807
Dividends declared:
Preferred stock............ (562)
Common stock............... (17,802)
Common stock issued:
DRP*....................... 270,871 903 6,177
KESOP*..................... 69,500 232 1,307
Redemption of preferred
stock...................... (6) (15,120)
---------- ------- -------- -------- ------ --------
BALANCE AT SEPTEMBER 30,
1993....................... 12,890,112 42,967 90,713 66,408 2,572 2,820
Net income................... 24,485
Dividends declared:
Preferred stock............ (309)
Common stock............... (18,831)
Common stock issued:
DRP*....................... 372,379 1,242 8,115
KESOP*..................... 28,000 93 577
Capital stock expense........ (62)
Redemption of preferred
stock...................... (198) 189 (99)
---------- ------- -------- -------- ------ --------
BALANCE AT SEPTEMBER 30,
1994....................... 13,290,491 44,302 99,145 71,942 2,572 2,721
Net income................... 23,128
Dividends declared:
Preferred stock............ (299)
Common stock............... (19,748)
Common stock issued:
DRP*....................... 42,103 140 864
KESOP*..................... 20,800 69 360
Capital stock expense........ (17)
Redemption of preferred
stock...................... (13) (144)
---------- ------- -------- -------- ------ --------
BALANCE AT SEPTEMBER 30,
1995....................... 13,353,394 $44,511 $100,339 $ 75,023 $2,572 $ 2,577
========== ======= ======== ======== ====== ========
- ---------------
<FN>
* Dividend reinvestment, employee saving, and key employee stock option plans.
The accompanying notes are an integral part of these statements.
17
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BAY STATE GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 1995, 1994, AND 1993, IN THOUSANDS
1995 1994 1993
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................ $23,128 $24,485 $22,807
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 26,026 24,209 21,562
Deferred income taxes................................... 6,908 5,254 6,803
Changes in operating assets and liabilities:
Accounts receivable..................................... 3,427 (1,342) (3,377)
Inventories and fuel purchase commitments............... 105 3,929 (1,570)
Accounts payable........................................ 1,410 (268) (1,699)
Deferred and accrued taxes.............................. (3,850) 3,428 (1,359)
Deferred gas costs and refunds due customers............ 12,492 17,291 (15,217)
Prepayments and other................................... 3,234 (10,933) (12,358)
------- ------- -------
Net cash provided by operating activities................. 73,739 66,053 15,592
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to plant (excluding AFUDC)...................... (53,336) (51,214) (46,639)
Investments in energy ventures............................ (4,586) (956) (4,779)
------- ------- -------
Net cash used in investing activities..................... (57,922) (52,170) (51,418)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock.................................. 1,416 9,965 8,619
Dividends on common stock................................. (19,748) (18,831) (17,802)
Dividends on preferred stock.............................. (299) (309) (562)
Issuance of long-term debt................................ 20,000 25,000 81,000
Retirements of preferred stock and long-term debt......... (12,157) (14,297) (50,438)
Short-term debt........................................... (6,250) (12,700) 14,950
------- ------- -------
Net cash provided by (used in) financing activities....... (17,038) (11,172) 35,767
------- ------- -------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH
INVESTMENTS............................................. (1,221) 2,711 (59)
Cash and temporary cash investments at beginning of
period.................................................. 3,980 1,269 1,328
------- ------- -------
Cash and temporary cash investments at end of period...... $ 2,759 $ 3,980 $ 1,269
======= ======= =======
Supplemental cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized).................... $16,355 $15,659 $12,788
======= ======= =======
Income taxes............................................ $ 8,720 $ 9,026 $ 8,428
======= ======= =======
The accompanying notes are an integral part of these statements.
18
19
BAY STATE GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1995, 1994, AND 1993
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
the accounts of Bay State Gas Company and its wholly owned subsidiaries (the
"Company"). All significant intercompany transactions and accounts have been
eliminated. Certain information in the prior period financial statements has
been reclassified to conform with the current period's presentation.
REGULATION AND OPERATIONS. The Company is subject to regulation with
respect to rates, accounting and other matters, where applicable, by the
Massachusetts Department of Public Utilities ("MADPU"), the New Hampshire Public
Utilities Commission, the Maine Public Utilities Commission, and the FERC. The
Company's accounting policies conform to generally accepted accounting
principles and reflect the effects of the ratemaking process in accordance with
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation."
PLANT. Plant is stated at original cost and consists of utility plant and
non-utility plant assets. The original cost of depreciable units of plant
retired, together with the cost of removal, net of salvage, is charged to
accumulated depreciation. The costs of maintenance, repairs, and replacements of
minor items are charged to expense as incurred.
Depreciation is provided for all classes of plant on a group straight-line
basis in amounts equivalent to overall composite rates of 3.88% for 1995 and
1994 and 3.74% for 1993.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC). AFUDC is the
estimated cost of funds used for construction purposes. Such allowances are
charged to plant and reported as other income (cost of equity funds) or a
reduction of interest expense (cost of borrowed funds). AFUDC was $748,000,
$457,000, and $2,028,000 for 1995, 1994, and 1993, respectively.
INVESTMENTS. The Company accounts for its partnership investments by the
equity method.
CASH AND TEMPORARY CASH INVESTMENTS. The Company considers all highly
liquid debt instruments purchased with an original maturity of three months or
less to be cash equivalents.
LOCAL TRANSPORTATION, NATURAL GAS SALES, AND DEFERRED GAS COSTS. Local
transportation revenue and natural gas sales are based on the volume of gas
transported or sold at billing rates authorized by regulatory authorities and
include unbilled revenues for gas delivered, but not billed. The Company's rates
include cost of gas adjustment clauses pursuant to which gas and certain other
costs are recovered from customers. Any differences between gas costs incurred
and amounts billed are deferred for recovery from or refund to customers in
future periods. Also included in natural gas sales are sales to interruptible
customers. Substantially all net margins from interruptible sales are used to
reduce gas costs to customers through the cost of gas adjustment clauses.
ENVIRONMENTAL COSTS. In accordance with orders of regulatory authorities,
the Company defers costs incurred to remediate environmental damage. Such costs
are amortized to expense over periods of seven to 10 years as they are recovered
from customers (see note 8).
INCOME TAXES. On October 1, 1993, the Company adopted the asset and
liability method of accounting for income taxes as required by Statement of
Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income
Taxes." Pursuant to SFAS 109, deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the tax
bases and the financial statement carrying amounts of existing assets and
liabilities. Prior year financial statements reflect deferred income taxes for
the tax effects of the timing differences between the recognition of revenue and
expense for income tax purposes and financial reporting purposes (see note 2).
19
20
Investment tax credits related to plant additions prior to 1987 were
deferred and are being amortized as reductions of income tax expense over the
lives of the related assets.
PENSION AND OTHER EMPLOYEE BENEFIT PLANS. The Company has noncontributory
defined benefit pension plans covering substantially all employees. Benefits
under the plans are generally based on years of service and the level of
compensation during the final years of employment. Pension costs are recognized
on the accrual method of accounting over the expected periods of employee
service based on actuarial assumptions.
Statements of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefit Plans Other than Pensions" and No. 112,
"Employers' Accounting for Postemployment Benefits," were adopted on October 1,
1993, requiring the accrual method of accounting for the costs of postretirement
and postemployment benefits. Other postretirement benefits consist of certain
health and life insurance benefits for retired and active employees hired before
September 30, 1990. Postemployment benefits consist of workers compensation
claims, long-term disability payments, and medical coverage continuation
payments. These costs were previously recognized when paid. They are now accrued
over the expected periods of employee service based on actuarial assumptions
(see note 7).
EARNINGS PER SHARE. Earnings per common share have been computed by
dividing earnings applicable to common stock by the weighted average number of
shares of common stock outstanding during each year.
NEW ACCOUNTING STANDARDS. Effective for fiscal years beginning after
December 15, 1995, SFAS 121 will require a review of long-lived assets for
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. It is expected that the
adoption of this standard will not have a material impact on cash flows,
financial condition, or the results of operations.
NOTE 2. INCOME TAXES
The components of income tax expense are as follows:
In thousands 1995 1994 1993
------------ ------- ------- -------
Current:
Federal............................................ $ 6,699 $ 8,918 $ 5,874
State.............................................. 1,368 1,870 1,450
------- ------- -------
Total current.............................. 8,067 10,788 7,324
------- ------- -------
Deferred:
Federal............................................ 5,799 4,716 5,726
State.............................................. 1,109 538 1,077
------- ------- -------
Total deferred............................. 6,908 5,254 6,803
------- ------- -------
Deferred investment tax credits, net................. (400) (400) (400)
------- ------- -------
Total income tax expense................... $14,575 $15,642 $13,727
======= ======= =======
The annual provision for deferred income taxes is comprised of the following:
In thousands 1995 1994 1993
------------ ------ ------ ------
Deferred gas costs.................................. $ 551 $ (750) $1,599
Accelerated tax depreciation........................ 3,681 2,962 4,899
Capitalized overheads............................... (2,225) 174 (918)
Pension............................................. 1,252 1,283 397
Demand side management costs........................ 1,569 (1,981) (818)
Postretirement benefits............................. 1,002 2,135 893
Investment in MASSPOWER............................. 602 1,119 3
Other............................................... 476 312 748
------ ------ ------
Total deferred income tax expense......... $6,908 $5,254 $6,803
====== ====== ======
20
21
A reconciliation of statutory federal income tax rates to the Company's effective income
tax rates is as follows:
In thousands 1995 1994 1993
------------ ---- ---- ----
Federal income tax rate..................................... 35% 35% 35%
State income taxes, net of federal benefit.................. 4 4 4
Other....................................................... - - (1)
-- -- --
Effective income tax rate................................... 39% 39% 38%
== == ==
Temporary differences that resulted in deferred income tax assets and liabilities as of
September 30, 1995 and 1994 are as follows:
In thousands 1995 1994
------------ ------- -------
Deferred income tax assets:
Allowance for doubtful accounts.............................. $ 1,716 $ 2,195
Inventory and overhead costs................................. 1,702 1,119
Unamortized investment tax credits........................... 3,753 3,983
Other........................................................ 2,600 3,709
------- -------
Total deferred income tax assets..................... 9,771 11,006
------- -------
Deferred income tax liabilities:
Prepaid pension and other benefits........................... 12,860 9,924
Plant related................................................ 69,717 66,834
Other........................................................ 3,217 2,379
------- -------
Total deferred income tax liabilities................ 85,794 79,137
------- -------
Net deferred income tax liability.............................. $76,023 $68,131
======= =======
At September 30, 1995 and 1994, unamortized deferred investment tax credits
included in long-term deferred taxes amounted to $5.8 million and $6.2 million,
respectively.
As discussed in note 1, a new method of accounting for income taxes was
adopted as of October 1, 1993. The cumulative effect on the years prior to
October 1, 1993 of adopting the new method of accounting for income taxes had no
effect on net income because a regulatory asset of $9.6 million was recorded,
reflecting future amounts due from customers for the effects of the temporary
differences. The effect of the change on income tax expense for 1994 was not
significant because amounts of income tax expense which differ from amounts
calculated in accordance with currently effective rate orders for settlement
with customers in future periods have been deferred.
NOTE 3. CAPITALIZATION
COMMON STOCK. A Key Employee Stock Option Plan provided for the granting
of options to key employees to purchase an aggregate of 1,050,000 shares of
common stock. While it is anticipated that no further options will be granted
under this plan, previously granted options may continue to be exercised through
2002.
Options are exercisable upon grant and expire within 10 years from the date of grant.
Option activity is as follows:
OPTION PRICE
OPTIONS OUTSTANDING AND EXERCISABLE SHARES PER SHARE
----------------------------------- ------- -------------
September 30, 1992........................................ 774,000 $17.75-$22.00
Options exercised......................................... (69,500) $17.75-$22.00
-------
September 30, 1993........................................ 704,500 $17.75-$22.00
Options exercised......................................... (28,000) $17.75-$22.00
-------
September 30, 1994........................................ 676,500 $17.75-$22.00
Options exercised......................................... (20,800) $17.75-$19.63
-------
September 30, 1995........................................ 655,700 $17.75-$22.00
-------
21
22
A Shareholder Rights Plan provides one right ("Right") to buy one share of
common stock at a purchase price of $70 for each share of common stock issued
and to be issued. The Rights expire on November 30, 1999 and only become
exercisable, or separately transferable, 10 days after a person or group
acquires, or announces an intention to acquire, beneficial ownership of 20% or
more of the Company's common stock. The Rights are redeemable by the Board at a
price of $.01 per Right, at any time prior to the acquisition by a person or a
group of beneficial ownership of 20% or more of the Company's common stock. Once
a person or group acquires more than 20% of the Company's common stock, however,
the Rights may not be redeemed.
At September 30, 1995, there were 385,000 authorized but unissued shares of
common stock reserved for the Dividend Reinvestment Plan ("DRP"). On December 1,
1994, the DRP was converted to a market based plan. It is anticipated that no
further shares will be issued under this plan.
CUMULATIVE PREFERRED STOCK AND LONG-TERM DEBT. The cumulative preferred
stocks rank equally and are preferred over common stock in voluntary liquidation
at the redemption price in effect at the time of such voluntary liquidation and
in involuntary liquidation at the par value per share, in each case plus accrued
dividends, except for the $3.80 Series, $50 par value, which has a voluntary
liquidation value of $83 per share and a set involuntary liquidation value of
$81.50 per share, plus accrued dividends.
SINKING FUND REQUIREMENTS AND MATURITIES. Annual sinking fund requirements and maturities of
long-term debt and preferred stock for the next five years and thereafter are as follows:
REDEEMABLE
LONG-TERM PREFERRED MAXIMUM
In thousands DEBT STOCK CASH REQUIRED
------------ --------- ---------- -------------
1996........................................... $ -- $ 180 $ 180
1997........................................... 6,000 180 6,180
1998........................................... 5,000 180 5,180
1999........................................... 833 180 1,013
2000........................................... 10,833 143 10,976
Thereafter..................................... 176,334 1,714 178,048
-------- ------ --------
Total.......................................... $199,000 $2,577 $201,577
======== ====== ========
As of September 30, 1995, long-term debt agreements contain no provisions
restricting the payment of dividends on common stock. All debt is unsecured.
As of September 30, 1995 and 1994, $6.0 million and $18.0 million of
long-term debt were outstanding under revolving credit agreements at weighted
average interest rates of 6.23% and 5.36%, respectively.
FAIR VALUES OF FINANCIAL INSTRUMENTS. The estimated fair values of the Company's financial
instruments are as follows:
ESTIMATED
CARRYING FAIR
In thousands AMOUNT VALUE
------------ -------- --------
September 30, 1995
Capital lease obligations............................... $ 2,720 $ 2,749
Long-term debt.......................................... $199,000 $212,365
September 30, 1994
Capital lease obligations............................... $ 3,747 $ 3,805
Long-term debt.......................................... $191,000 $184,000
The fair values of capital lease obligations are estimated using the
present value of the minimum lease payments discounted at market rates. The fair
values of long-term debt are estimated based on current rates offered to the
Company for debt of the same remaining maturities. The carrying amounts for cash
and temporary cash investments, accounts receivable, accounts payable, accrued
liabilities, and short-term debt approximate their fair values due to the
short-term nature of these instruments.
22
23
NOTE 4. LEASES
Noncancelable operating and capital leases have been entered into for the
use of certain facilities and equipment. The operating lease agreements
generally contain renewal options. The capital leases relate to liquefied
natural gas storage facilities. Certain leases contain renewal and purchase
options and escalation clauses.
Future annual minimum rental payments under long-term noncancelable leases at September 30, 1995,
are as follows:
CAPITAL OPERATING
In thousands LEASES LEASES
------------ ------ ---------
1996............................................................ $1,281 $1,836
1997............................................................ 1,004 1,597
1998............................................................ 726 1,149
1999............................................................ -- 760
2000............................................................ -- 214
------ -------
Future minimum lease payments................................... 3,011 $5,556
======
Less amount representing interest............................... 291
------
Present value of future minimum lease payments.................. $2,720
======
In conformity with its regulatory accounting requirements, rent expense is recorded as if all
leases were operating leases. The following rentals were charged to operating expenses:
CAPITAL OPERATING
In thousands LEASES LEASES
------------ ------ ---------
1995............................................................ $1,281 $ 5,437
1994............................................................ $1,281 $ 5,179
1993............................................................ $1,281 $ 5,697
Interest included in capital lease payments was $253,000, $328,000, and
$397,000 in 1995, 1994, and 1993, respectively.
NOTE 5. SHORT-TERM DEBT AND LINES OF CREDIT
1995 1994
---- ----
Unsecured bank lines of credit
Principal outstanding (thousands)............................ $21,500 $ 7,750
Weighted average interest rate............................... 6.97% 5.55%
Commercial paper
Principal outstanding (thousands)............................ $10,000 $30,000
Weighted average interest rate............................... 5.80% 4.82%
Total short-term debt
Principal outstanding (thousands)............................ $31,500 $37,750
Weighted average interest rate............................... 6.60% 4.97%
At September 30, 1995, the Company had unsecured bank lines of credit
aggregating $77.0 million for which it pays commitment fees, and access to an
additional $30.0 million under the Fuel Purchase Agreements as described in note
6.
NOTE 6. FUEL PURCHASE AGREEMENTS
Up to $30.0 million can be raised through credit agreements (the
"Agreements") underlying the Fuel Purchase Agreements with a corporation
established to provide financing, through borrowing on a demand basis or selling
supplemental gas inventories. Any inventories sold must be repurchased and any
associated carrying costs paid when the gas is withdrawn from storage. All gas
costs, carrying costs, and administrative charges are fully recoverable through
the CGA approved in each state regulatory jurisdiction. The Agreements contain
an expiration date of September 1998.
23
24
NOTE 7. PENSION AND EMPLOYEE BENEFIT PLANS
PENSION PLANS. The funded status of the Company's pension plans as of September 30, 1995
and 1994, is as follows:
In thousands 1995 1994
------------ ---- ----
Vested benefits................................................ $58,877 $57,956
Nonvested benefits............................................. 1,196 1,103
------- -------
Accumulated benefit obligation................................. 60,073 59,059
Additional benefits related to future compensation levels...... 12,247 13,477
------- -------
Projected benefit obligation................................... 72,320 72,536
Plan assets at fair value...................................... 81,896 75,417
------- -------
Plan assets in excess of plan benefit obligations.............. $ 9,576 $ 2,881
======= =======
Plan assets are primarily invested in marketable pooled funds holding
equity and corporate debt securities and in cash equivalents. Certain changes in
items shown above are not recognized as they occur, but are systematically
amortized over subsequent periods. Unrecognized amounts as of September 30, 1995
and 1994, are as follows:
In thousands 1995 1994
------------ ---- ----
Unrecognized net gain........................................ $ (6,010) $ (1,878)
Unrecognized prior service cost.............................. 5,178 6,420
Unrecognized net transition obligation....................... 4,849 5,832
Prepaid pension costs included in the Consolidated Balance
Sheets..................................................... (13,593) (13,255)
-------- --------
Plan assets in excess of plan benefit obligations............ $ 9,576 $ 2,881
======== ========
The discount rate, rate of increase in future compensation levels, and
expected long-term rate of return on plan assets used in determining the
actuarial present value of the projected benefit obligation were 8.0%, 5.0%, and
9.0% for both 1995 and 1994. Net pension cost for 1995, 1994, and 1993 included
the following components:
In thousands 1995 1994 1993
------------ ---- ---- ----
Service cost-benefits earned......................... $ 1,790 $ 2,021 $ 1,654
Interest cost on benefit obligations................. 5,668 5,580 5,318
Actual return on plan assets......................... (9,762) (129) (6,886)
Net amortization and deferral........................ 14,431 (4,642) 2,862
------- ------- -------
Net pension cost..................................... $ 2,127 $ 2,830 $ 2,948
======= ======= =======
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS. As described in note 1, the
Company adopted the accrual method of accounting for postretirement benefit
plans other than pensions in 1994. The change in the method of accounting had no
significant impact in 1994 as regulatory authorities permit the Company to defer
costs in excess of amounts recovered through rates for collection in future
periods. The present value of the accumulated benefit obligation was $24.7
million and $28.2 million, at September 30, 1995 and 1994, respectively. The
expense recognized was $2.7 million, $2.8 million, and $2.5 million for 1995,
1994, and 1993, respectively. The components of other postretirement benefit
expense for 1995 and 1994 are as follows:
In thousands 1995 1994
------------ ---- ----
Interest cost................................................... $ 1,872 $2,112
Service cost.................................................... 445 575
Actual return on assets......................................... (2,848) (365)
Net amortization................................................ 2,581 848
Deferred........................................................ 613 (388)
------- ------
Other postretirement benefit expense............................ $ 2,663 $2,782
======= ======
24
25
The funded status of the Company's other postretirement benefit plans as of September 30, 1995
and 1994, is as follows:
In thousands 1995 1994
------------ ---- ----
Retirees..................................................... $ 12,742 $ 14,616
Fully eligible active employees.............................. 3,992 4,325
Other active employees....................................... 7,961 9,243
-------- --------
Accumulated other postretirement benefit obligation.......... 24,695 28,184
Fair value of plan assets.................................... (18,133) (16,269)
Unrecognized net transition obligation....................... (22,732) (23,995)
Unrecognized net gain........................................ 6,711 882
-------- --------
Prepaid other postretirement benefits recorded in the
Consolidated Balance Sheets................................ $ 9,459 $(11,198)
======== ========
Plan assets are held in voluntary employee benefit association ("VEBA")
trusts and medical funds in the pension plans. VEBA assets are invested in
common stocks, bonds, and cash equivalents.
The accumulated other postretirement benefit obligation was determined
using an assumed discount rate of 8.0% and an expected long-term pre-tax rate of
return on plan assets of 9.0% for both 1995 and 1994, and a health care cost
trend rate of 9.0% and 11.0% in 1995 and 1994, respectively, decreasing to 6.0%
by 1998. An annual 1% increase in the health care cost trend rate would increase
the accumulated postretirement benefit obligation by $2.2 million and the cost
for 1995 by $300,000.
RETURN ON PREPAYMENTS OF OTHER POSTRETIREMENT BENEFITS. As permitted by
regulatory authorities, noncash returns of $1,650,000, $857,000, and $286,000
for 1995, 1994, and 1993, respectively, have been recorded on amounts of
prepayments associated with employee postretirement benefit plans other than
pensions. Regulators permit the accrual of returns on these prepayments because
the plan funding will significantly reduce future costs of the plans.
POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS. As described in note 1, the
accrual method of accounting for postemployment benefit plans was adopted in
1994. The change in the method of accounting had no significant impact in 1994
as the Company deferred costs in excess of amounts recovered through rates for
collection in future periods. The present value of the accumulated benefit
obligation was $4.9 million and $4.1 million, at September 30, 1995 and 1994,
respectively.
EMPLOYEE SAVINGS PLAN. Employee Savings Plans (the "ESP's") provides
eligible employees with an incentive to save and invest regularly. The ESP's are
defined contribution plans, which allow eligible employees to defer a portion of
their salaries to employee-funded pretax retirement savings accounts. Matching
contributions to certain employee deferrals were $813,000, $784,000, and
$601,000 in 1995, 1994, and 1993, respectively.
NOTE 8. COMMITMENTS AND CONTINGENCIES
CAPACITY REQUIREMENTS. The Company currently transports natural gas from
Canada through a converted oil pipeline leased from the Portland Pipe Line
Corporation ("PPLC"). The PPLC lease currently extends to March 31, 1997. An
agreement with PPLC to extend the lease through the 1997-1998 heating season is
being sought. Short-term contingency plans have been developed for supplying
customers in Maine and New Hampshire through the 1997-1998 heating season in the
event that the lease is not extended. Long-term, two projects to replace the
pipeline capacity provided by the PPLC lease are being pursued, a 2.0 million
MMBtu liquefied natural gas storage facility in Wells, Maine ("Wells LNG"), and
the Portland Natural Gas Transmission System ("PNGTS").
25
26
INVESTMENT RECOVERY. The following table summarizes the Company's current investment in energy ventures:
INVESTMENTS
OWNERSHIP ---------------
PERCENTAGES 1995 1994
----------- ---- ----
MASSPOWER............................................ 17.5% $2,394 $2,957
PNGTS................................................ 29.0 3,793 2,645
Wells LNG............................................ 100.0 3,521 151
KBC.................................................. 33.3 6 --
Other................................................ -- 54 134
----- ------ ------
Total................................................ $9,768 $5,887
===== ====== ======
PNGTS is an interstate pipeline that will extend 250 miles from the
US-Canadian border to the New Hampshire-Massachusetts border. By March 1, 1996,
PNGTS plans to file an application with the FERC for approval to construct and
operate the pipeline. The Company has entered into long-term agreements with
PNGTS for service on the pipeline. Such agreements are subject to state
regulatory review and approval in Massachusetts, Maine, and New Hampshire. In
November 1994, the Company filed an application with the FERC for approval to
construct and operate Wells LNG. The Company will file for approval from the
public utility commissions of Maine and New Hampshire of its agreement for
service from the LNG facility.
Recovery of investments in PNGTS and Wells LNG is dependent upon, among
other things, successful completion of the projects and the terms of required
regulatory approvals. While their completion is subject to a number of factors
beyond the Company's control, the Company believes that these projects will be
successful. Both of these projects are scheduled to be completed and available
for service by November 1998.
During 1995, the Company made an initial investment of $50,000 in KBC and
is committed to invest up to a total of $1.7 million. KBC began operations in
1995.
LONG-TERM OBLIGATIONS. The Company has long-term contracts for the
purchase, storage, and delivery of gas supplies. Certain of these contracts
contain minimum purchase provisions which, in the opinion of management, are not
in excess of the Company's requirements.
ENVIRONMENTAL ISSUES. Like other companies in the natural gas industry,
the Company is party to governmental actions associated with former gas
manufacturing sites. Management estimates that, exclusive of insurance
recoveries, if any, expenditures to remediate and monitor known environmental
sites will range from $3.9 million to $10.0 million. Accordingly, a $3.9 million
liability, with an offsetting charge to a regulatory asset (see note 1), has
been accrued. Environmental expenditures for 1995, 1994, and 1993 were $387,000,
$129,000, and $620,000, respectively. Exclusive of amounts accrued for future
expenditures, at September 30, 1995 and 1994, approximately $3.0 million of
environmental expenditures had been deferred for future recovery from customers.
REGULATORY MATTERS. On April 13, 1995, approval was received from the FERC
for a $1.1 million increase in annual pipeline revenues effective November 1,
1994.
An overall revenue-neutral rate redesign has been filed with the MADPU. The
goal of the rate redesign is to implement rates that more closely reflect the
actual costs associated with serving different customers. New rates are expected
to be effective early in calendar 1996.
Significant regulatory assets arising from the rate-making process
associated with income taxes, employee benefits, and environmental response
costs have been recorded. Based on its assessments of decisions by regulatory
authorities, management believes that all regulatory assets will be settled at
recorded amounts through specific provisions of current and future rate orders.
LITIGATION. The Company is involved in various legal actions and claims
arising in the normal course of business. Based on its current assessment of the
facts of law, and consultations with outside counsel, management does not
believe that the outcome of any action or claim will have a material effect upon
the consolidated financial position, results of operations, or liquidity of the
Company.
26
27
NOTE 9. UNAUDITED QUARTERLY FINANCIAL DATA
In thousands except per share amounts.
QUARTER ENDED
-----------------------------------------------------
FISCAL 1995 DECEMBER 31 MARCH 31 JUNE 30 SEPTEMBER 30
----------- ----------- -------- ------- ------------
Operating revenues................. $ 119,286 $174,269 $75,693 $ 48,870
Operating income (loss)............ $ 20,616 $ 39,016 $ 186 $ (6,979)
Net income (loss).................. $ 10,477 $ 21,376 $(2,290) $ (6,435)
Per average common share:
Income (loss).................... $ .78 $ 1.60 $ (.18) $ (.48)
Dividend declared and paid....... $ .365 $ .365 $ .375 $ .375
FISCAL 1994
-----------
Operating revenues................. $ 139,328 $210,019 $67,043 $ 46,890
Operating income (loss)............ $ 23,806 $ 40,757 $(1,827) $ (8,620)
Net income (loss).................. $ 11,798 $ 22,819 $(3,037) $ (7,095)
Per average common share:
Income (loss).................... $ .91 $ 1.75 $ (.24) $ (.54)
Dividend declared and paid....... $ .355 $ .355 $ .365 $ .365
In the opinion of management, quarterly financial data includes all
adjustments, consisting only of normal recurring accruals, necessary for a fair
representation of such information. Revenue and income amounts vary
significantly due to seasonal weather conditions.
27
28
REPORT OF MANAGEMENT
The management of Bay State Gas Company and its subsidiaries has the
responsibility for preparing the accompanying financial statements. We believe
the financial statements were prepared in conformity with generally accepted
accounting principles. Management also prepared the other information in the
annual report and is responsible for its accuracy and consistency with the
financial statements.
To fulfill its responsibility, management maintains a system of internal
control that has been designed to provide reasonable assurance as to the
integrity and reliability of the financial statements and the safeguarding of
Company assets.
The Company has established statements of corporate policy relating to
conflict of interest and conduct of business and annually receives from
appropriate employees confirmation of compliance with these policies.
The Company's financial statements have been audited by KPMG Peat Marwick
LLP, independent certified public accountants. The independent accountants are
elected by the Company's Directors and report any recommendations concerning the
Company's system of internal control to the Audit Committee of the Board of
Directors, which consists of three outside Directors. The Audit Committee meets
periodically with management, internal auditors and KPMG Peat Marwick LLP, to
review and monitor the Company's financial reporting, accounting practices, and
business conduct.
Although there are inherent limitations in any system of internal control,
management believes that as of September 30, 1995, the Company's system of
internal control was adequate to accomplish the objectives discussed herein.
ROGER A. YOUNG THOMAS W. SHERMAN
Chief Executive Officer Chief Financial Officer
28
29
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders of
BAY STATE GAS COMPANY
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Bay State Gas Company and subsidiaries as of September 30,
1995 and 1994, and the related consolidated statements of earnings,
shareholders' equity and cash flows for each of the years in the three-year
period ended September 30, 1995. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits 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 Bay State Gas Company and
subsidiaries at September 30, 1995 and 1994, and the results of their operations
and their cash flows for each of the years in the three-year period ended
September 30, 1995 in conformity with generally accepted accounting principles.
As discussed in Notes 1, 2, and 7 to the consolidated financial statements,
the Company changed its methods of accounting for income taxes, postemployment
benefits and postretirement health and welfare benefits in 1994.
KPMG PEAT MARWICK LLP
Boston, Massachusetts
October 24, 1995
29
30
PART III
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the Directors of the Registrant as set forth on pages
3 and 4 of the 1996 annual meeting proxy statement, dated December 7, 1995, is
incorporated herein by reference. Information relating to the Executive Officers
of the Registrant is contained in Part I, Item 1, Business.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding compensation of the Registrant's executive officers
as set forth on pages 7 through 15 of the 1996 annual meeting proxy statement,
dated December 7, 1995, is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information regarding the security ownership of certain beneficial owners
and management as set forth on pages 5 and 6 of the 1996 annual meeting proxy
statement, dated December 7, 1995, is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions as set
forth on pages 4, 6, 7 and 15 of the 1996 annual meeting proxy statement, dated
December 7, 1995, is incorporated herein by reference.
30
31
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THE REPORT:
(1) The following financial statements are included herein under Part II,
Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Consolidated Statements of Earnings for the Years ended September 30,
1995, 1994, and 1993
Consolidated Balance Sheets as of September 30, 1995 and 1994
Consolidated Statements of Capitalization as of September 30, 1995 and
1994
Consolidated Statements of Shareholders' Equity for the Years ended
September 30, 1995, 1994, and 1993
Consolidated Statements of Cash Flows for the Years ended September
30, 1995, 1994, and 1993 Independent Auditors' Report
(2) The following additional data should be read in conjunction with the
financial statements included in Part II, Item 8, FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA. Schedules not included herein have been omitted because they
are not required or are not applicable, or the required information is shown in
such financial statements or notes thereto.
PAGES IN
FORM 10-K
----------
VIII Consolidated Valuation and Qualifying Accounts -- 1995, 1994 and 1993 32
Independent Auditors' Report 29
(3) Exhibits -- See Exhibit index on page 34.
(B) REPORTS ON FORM 8-K:
The Company did not file a report on Form 8-K during the fourth quarter of
fiscal 1995.
31
32
SCHEDULE VIII
BAY STATE GAS COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED SEPTEMBER 30, 1995, 1994, AND 1993
(IN THOUSANDS)
ADDITIONS
BALANCE AT CHARGED TO BALANCE AT
BEGINNING OF COSTS AND END OF
DESCRIPTION PERIOD EXPENSES DEDUCTIONS(A) PERIOD
- ----------- ------------ ---------- ------------- ----------
YEAR ENDED SEPTEMBER 30, 1995
Allowance for doubtful accounts......................... $5,072 $5,007 $ 5,847 $4,232
====== ====== ======= ======
YEAR ENDED SEPTEMBER 30, 1994
Allowance for doubtful accounts......................... $4,468 $7,778 $ 7,174 $5,072
====== ====== ======= ======
YEAR ENDED SEPTEMBER 30, 1993
Allowance for doubtful accounts......................... $4,251 $6,990 $ 6,773 $4,468
====== ====== ======= ======
<FN>
- ---------------
(a) Write-off of uncollectible accounts, net of recoveries.
32
33
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BAY STATE GAS COMPANY
/S/ THOMAS W. SHERMAN
By ---------------------------------
THOMAS W. SHERMAN
EXECUTIVE VICE PRESIDENT
Date: December 1, 1995
------------------------------
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 and on the dates indicated.
SIGNATURE CAPACITY DATE
--------- -------- ----
/S/ CHARLES H. TENNEY II Director December 1, 1995
- --------------------------------------
CHARLES H. TENNEY II
(CHAIRMAN OF THE BOARD OF DIRECTORS)
/S/ ROGER A. YOUNG Chief Executive Officer; December 1, 1995
- -------------------------------------- Director
ROGER A. YOUNG
(PRESIDENT)
/S/ JOEL L. SINGER Chief Operating Officer; December 1, 1995
- -------------------------------------- Director
JOEL L. SINGER
(EXECUTIVE VICE PRESIDENT)
/S/ THOMAS W. SHERMAN Chief Financial and Accounting December 1, 1995
- -------------------------------------- Officer; Director
THOMAS W. SHERMAN
(EXECUTIVE VICE PRESIDENT)
/S/ LAWRENCE J. FINNEGAN Director December 1, 1995
- --------------------------------------
LAWRENCE J. FINNEGAN
/S/ DOUGLAS W. HAWES Director December 1, 1995
- --------------------------------------
DOUGLAS W. HAWES
/S/ WALTER C. IVANCEVIC Director December 1, 1995
- --------------------------------------
WALTER C. IVANCEVIC
/S/ JOHN H. LARSON Director December 1, 1995
- --------------------------------------
JOHN H. LARSON
/S/ JACK E. MCGREGOR Director December 1, 1995
- --------------------------------------
JACK E. MCGREGOR
/S/ DANIEL J. MURPHY III Director December 1, 1995
- --------------------------------------
DANIEL J. MURPHY III
/S/ GEORGE W. SARNEY Director December 1, 1995
- --------------------------------------
GEORGE W. SARNEY
33
34
EXHIBIT INDEX
(3) Articles of incorporation and by-laws:
EXHIBIT
NO. DESCRIPTION REFERENCE
- ------- ----------- ---------
*3.1 Articles of Incorporation Exhibit 3.1 to Form 10-Q
dated February 9, 1995 (File No.
1-7479)
*3.2 By-Laws, as amended Exhibit 3.2 to Form 10-Q
dated February 9, 1995 (File No.
1-7479)
<FN>
- ---------------
* Incorporated by reference to the indicated filing.
(4) Instruments defining the rights of security holders, including indentures:
The following is a listing of debt instruments defining the rights of
security holders, including indentures and/or note agreements for Bay State,
Northern, and Granite. None of these instruments represent any securities in an
amount authorized or outstanding which exceeds 10% of the total assets of the
Company as of September 30, 1995. The Company will furnish the Securities and
Exchange Commission with copies of any of the instruments listed below upon
request.
Revolving Credit Agreement between Northern and The First National Bank of
Boston, to borrow up to $20,000,000, dated as of March 17, 1993, due March 17,
1997.
Indenture between Bay State and The First National Bank of Boston, Trustee,
dated as of April 1, 1991, for Senior Unsecured Debt Securities under which the
following Notes have been issued under a Prospectus dated April 18, 1991:
- $10,000,000 Principal Amount of 9.20% Notes due June 6, 2011
- $5,000,000 Principal Amount of 9.28% Notes due August 12, 2021
- $25,000,000 Principal Amount of 9.45% Notes due September 5, 2031
- $12,000,000 Principal Amount of 8.15% Notes due August 26, 2022
- $4,000,000 Principal Amount of 7.55% Notes due November 1, 2002
- $1,000,000 Principal Amount of 7.55% Notes due October 2, 2002
- $5,000,000 Principal Amount of 7.45% Notes due December 16, 2002
- $5,000,000 Principal Amount of 7.38% Notes due December 31, 2002
- $7,000,000 Principal Amount of 7.375% Notes due November 1, 2002
- $1,000,000 Principal Amount of 7.375% Notes due December 31, 2002
- $5,000,000 Principal Amount of 7.37% Notes due December 31, 2002
- $20,000,000 Principal Amount of 7.25% Notes due August 5, 2002
Indenture between Bay State and The First National Bank of Boston, Trustee,
dated as of April 1, 1991, for Senior Unsecured Debt Securities under which the
following Notes have been issued under a Prospectus dated April 7, 1993:
- $10,000,000 Principal Amount of 7.42% Notes due September 10, 2001
- $10,000,000 Principal Amount of 7.625% Notes due June 19, 2023
- $10,000,000 Principal Amount of 6.0% Notes due July 6, 2000
- $15,000,000 Principal Amount of 6.0% Notes due September 29, 2003
- $10,000,000 Principal Amount of 6.58% Notes due June 21, 2005
- $5,000,000 Principal Amount of 6.0% Notes due January 30, 2001
- $5,000,000 Principal Amount of 6.625% Notes due June 28, 2002
Note Purchase Agreement between Northern and First Colony Life Insurance
for the purchase and sale of $13,000,000 principal amount of 9.70% Notes dated
as of January 1, 1992, due September 1, 2031.
34
35
Note Purchase Agreement between Northern and the Mutual Life Insurance
Company of New York for the purchase and sale of $10,000,000 principal amount of
6.93% Notes dated as of September 29, 1995, due September 27, 2010.
Note Purchase Agreement between Northern and the Mutual Life Insurance
Company of New York for the purchase and sale of $5,000,000 principal amount of
6.30% Notes dated as of September 29, 1995, due September 30, 1998.
(10) Material contracts:
EXHIBIT
NO. DESCRIPTION REFERENCE
- ------- ----------- ---------
*10.01 Key Employee Stock Option Plan covering key employees Exhibit 10.16 to Form 10-K
of the Company for 1989 (File No. 1-7479)
*10.02 Key Officer Deferred Compensation Plan covering the Exhibit 10.21 to Form 10-K
Chairman of the Board of Directors, the President, for 1992 (File No. 1-7479)
and all Vice Presidents of the Company
*10.03 Supplemental Executive Retirement Plan covering the Exhibit 10.22 to Form 10-K
Chairman of the Board of Directors, the President, for 1992 (File No. 1-7479)
and all Vice Presidents of the Company
*10.04 Key Employee Incentive Compensation Plan covering the Exhibit 10.23 to Form 10-K
Chairman of the Board of Directors, the President, for 1992 (File No. 1-7479)
and certain key employees of the Company
*10.05 Senior Advisory Agreement between Bay State and Exhibit 10.05 to Form 10-K
Charles H. Tenney II, dated January 27, 1994 for 1994 (File No. 1-7479)
10.06 Severance agreement between Bay State and each of the Filed herewith
executive officers of the Company
10.07 Directors' Retirement Plan Filed herewith
10.08 Key Employee Long-term Incentive Plan Filed herewith
(11) Statement re: computation of per share earnings, filed herewith.
(12) Statement re: computation of ratio of earnings to fixed charges, filed
herewith.
(21) Subsidiaries of the Registrant, filed herewith.
(23) Consent of Independent Auditors, filed herewith.
(27) Financial Data Schedule, filed herewith.
<FN>
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* Incorporated by reference to the indicated filing.
35