<PAGE>
FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended September 30, 1997 Commission file number: 1-7196
CASCADE NATURAL GAS CORPORATION
(Exact name of Registrant as specified in its charter)
Washington 91-0599090
---------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
222 Fairview Avenue North
Seattle, WA 98109 (206) 624-3900
------------------ --------------
(Address of principal executive offices) (Registrant's telephone number
including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on which Registered
- ------------------- -----------------------------------------
Common Stock, Par Value $1 per Share New York Stock Exchange
Preferred Stock Purchase Rights New York 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. ___
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant as of the close of business on November 30,
1997, was $184,028,000
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date.
Title Outstanding
Common Stock, Par Value $1 per Share 11,000,737 as of November 30, 1997
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for its 1998 Annual
Meeting of Shareholders are incorporated by reference into Part III, Items 10,
11, 12, and 13.
<PAGE>
CASCADE NATURAL GAS CORPORATION
ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION ON FORM 10-K
For the Fiscal Year Ended September 30, 1997
Table of Contents
Page
----
Number
- ------
Part I
Item 1 - Business 3
Item 2 - Properties 10
Item 3 - Legal Proceedings 11
Item 4 - Submission of Matters to a Vote of Security Holders 11
Executive Officers of the Registrant 12
Part II
Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters 13
Item 6 - Selected Financial Data 14
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 7a- Quantitative and Qualitative Disclosures about
Market Risk 21
Item 8 - Financial Statements and Supplementary Data 22
Item 9 - Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 43
Part III
Item 10 - Directors and Executive Officers of the Registrant 43
Item 11 - Executive Compensation 43
Item 12 - Security Ownership of Certain Beneficial Owners
and Management 43
Item 13 - Certain Relationships and Related Transactions 43
Part IV
Item 14 - Exhibits, Financial Statement Schedules and
Reports on Form 8-K 44
Signatures 45
Index to Exhibits 46
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ITEM 1. BUSINESS.
GENERAL
Cascade Natural Gas Corporation (Cascade or the Company) was incorporated
under the laws of the state of Washington on January 2, 1953. Its principal
business is the distribution of natural gas to customers in the states of
Washington and Oregon. Approximately 16% of its gas distribution revenues are
from the state of Oregon.
At September 30, 1997, there were 135,126 residential customers, 24,591
commercial customers, 347 firm industrial customers and 21 traditional
interruptible customers, all of which are classified as core customers. In
addition, there were 162 non-core customers. In the twelve month periods ended
September 30, 1997 and September 30, 1996, residential and commercial customers
accounted for 64% of the operating margin, and 20% of the total gas deliveries.
The non-core customers (including transportation service) provided the remaining
operating margin and throughput.
STATE REGULATION
The Company's rates and practices are regulated by the Washington Utilities
and Transportation Commission (WUTC) and the Oregon Public Utility Commission
(OPUC).
Cascade's gas supply contracts provide for annual review of gas prices for
possible adjustment. To the extent that prices are changed for core customers,
Cascade is able to pass the effect of such changes, subject to regulatory
review, to its customers by means of a periodic purchased gas cost adjustment
(PGA) in each state. Gas price changes occurring between times when PGA rate
changes become effective are deferred for pass through in the next PGA. With
respect to such gas supplies delivered to Oregon customers, 80% of the cost
changes between PGA effective dates is so deferred. The remaining 20% (increase
or decrease) is absorbed by the Company.
The Company is also subject to state regulation with respect to integrated
resource planning, and its most recent update of its Integrated Resource Plan
(IRP) was filed in 1996 with both the WUTC and the OPUC. The IRP shows the
Company's plan for the best set of supply and demand side resources that
minimizes costs and has acceptable levels of deliverability risk over the
twenty-year planning horizon. The IRP also sets forth possible growth scenarios
for core customers and throughput for a twenty-year period. In addition, the
IRP sets forth the Company's demand side management goals of achieving certain
conservation levels in customer usage. The Company's investments in
cost-effective demand side resources are recoverable in rates in both Washington
and Oregon.
The IRP also sets forth the Company's supply side management plans
regarding transportation capacity and gas supply acquisition over a twenty-year
period. The Company develops updates of the IRP every two years. These updated
documents take into account input solicited from the public and the WUTC and
OPUC staffs. While the filing of the IRP with both commissions gives the
Company no advance assurance that its acquisitions of pipeline transportation
capacity and gas supplies will be recognized in rates, management believes that
the integrated resource planning process benefits the Company by giving it the
opportunity to obtain input from regulators and the public concurrently with
making these important strategic decisions. Until the Company receives final
regulatory approval of these decisions in the context of a general
3
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rate case, the Company cannot predict with certainty the extent to which the
integrated resource planning process will affect its rates.
NATURAL GAS SUPPLY
The majority of Cascade's supply of natural gas is transported via Williams
Gas Pipelines - West (Williams), formerly Northwest Pipeline Corporation.
Williams owns and operates a transmission system extending from points of
interconnection with El Paso Natural Gas Company and Transwestern Pipeline
Company near Blanco, New Mexico through the states of New Mexico, Colorado,
Utah, Wyoming, Idaho, Oregon and Washington to the Canadian border near Sumas,
Washington. Natural gas is transported north from the Colorado and New Mexico
area, and south from British Columbia, Canada. The Company is also a shipper on
the Pacific Gas Transmission Company (PGT) system. PGT owns and operates a gas
transmission line that connects with the facilities of the Alberta Natural Gas
Company, Ltd. at the international border near Kingsgate, British Columbia and
extends through Washington and central Oregon into California.
Presently, baseload requirements for Cascade's core market group are
provided by six major gas supply contracts with various expiration dates from
1998 through 2008 and totaling 714,830 therms per day. Approximately 93% of the
gas supplied pursuant to the contracts is from Canadian sources. The remainder
is domestic. These contracts are supplemented by various service agreements to
cover periods of peak demand including three storage agreements with Williams.
One extends to October 31, 2014 and provides for 165,950 therms per day and a
maximum, renewable inventory of 5,973,780 therms. The second with the
Washington Water Power Company (WWP) has a primary term ending April 30, 2001
and entitles Cascade to receive up to 150,000 therms per day and a maximum,
renewable inventory of 4,800,000 therms. A third contract for liquefied natural
gas (LNG) storage is effective through October 31, 2014. Under this LNG
agreement, Cascade is entitled to receive up to 600,000 therms per day to a
maximum inventory of 5,622,000 therms. In addition to withdrawal and inventory
capacity, Cascade maintains a corresponding amount of firm transportation from
the storage facility to the city gate for each of these agreements.
In addition to underground and LNG storage, Cascade has entered into
contracts with two of its major industrial customers whereby each customer
agrees to switch to alternate fuel allowing Cascade to reduce firm deliveries to
that customer. Cascade then takes the end-user's firm gas supply and pipeline
capacity to serve its core markets. In return, Cascade reimburses the end-user
for the cost of its alternate fuel and pipeline capacity. Since the end-user is
also a distribution customer of Cascade, the supply is already being delivered
to Cascade's system and is merely diverted to other, core customers, allowing
for even greater accommodation of late day demand spikes. Because the
end-user's response is dictated by contract and firm gas supply and firm
pipeline capacity is involved, this type of resource is highly flexible and
reliable. The associated costs of this resource, including the loss of
distribution revenue and depending upon the relative price of the alternate
fuel, may be less expensive than the cycle cost of storage or maintaining
pipeline capacity on a year-round basis, plus a seasonal firm gas supply in
order to meet growth in peak day demand. Both of these agreements have met the
test for the "least cost resource alternative" under Cascade's Integrated
Resource Plan ("IRP") process. One such peak shaving agreement entitles Cascade
to call on 150,000 therms per day up to a seasonal total of 3,000,000 therms.
This contract expires on September 30, 2014. The second peak shaving
agreement, which expires on April 30, 2014, entitles Cascade to call on a
maximum of 500,000 therms per day and up to a seasonal total of 3,000,000
therms.
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Commencing December, 1995, Cascade entered into two peaking service
agreements with Canadian gas suppliers. These agreements provide for a maximum
daily quantity of 250,000 therms on peak days and a renewable inventory of
6,000,000 therms. Cascade can call upon these two service agreements any day
during the peak winter months of December, January and February. These service
agreements, while less reliable than firm storage service, are more flexible
than baseload gas supply contracts. Both agreements allow for same day
nomination and city gate delivery at a competitive cost. Each agreement has a
primary term of three years ending February, 1998.
Cascade maintains a diversified portfolio of natural gas supplies. During
1997, Cascade purchased approximately 79% of its gas supplies from firm gas
supply contracts and 21% from 30-day spot market contracts. In addition,
642,059,914 therms of customer purchased supplies were transported across
Cascade facilities.
CURRENT FEDERAL ENERGY REGULATORY COMMISSION (FERC) MATTERS
The following is a summary of current issues subject to FERC regulation
that will affect the amount the Company pays for interstate transportation of
natural gas supplies. Since the policies of the WUTC and the OPUC provide for
100% pass through of costs subject to FERC regulation, the Company expects that
the final resolution of these issues will not affect its net earnings.
On October 16, 1997 the FERC issued an order denying rehearing of the June
11 order on Williams' oldest pending rate case, RP93-5. In the June order, FERC
set policy on a method for determining a pipeline's rate of return on equity.
The policy set Williams' rate of return on equity at 12.59%. The FERC had
originally allowed Williams a 13.2% rate of return. The rates from RP93-5 were
in effect, subject to refund, from April 1, 1993 until November 1, 1994. The
lower rate of return will ultimately result in refunds from that period.
The FERC has not yet acted on the single issue under contention in the
Williams RP94-220 case. The issue involves the desire of the Canadian
Association of Petroleum Producers (CAPP) to have a mileage based zonal rate
replace Williams' current "postage stamp" rate which does not recognize distance
of flow. The Administrative Law Judge filed his initial decision in March, 1997
rejecting CAPP's arguments. RP94-220 rates were in effect from November 1, 1994
until February 1, 1996.
The initial decision from the Administrative Law Judge following litigation
of the Williams rate case RP95-409 is still pending. Final briefs were
submitted in March, 1997. One of the primary issues involves the FERC policy
for calculating the pipeline's rate of return on equity established in RP93-5
and its application in this case. The rates from RP95-409 were in effect,
subject to refund, from February 1, 1996 until March 1, 1997.
A settlement of Williams' most recent rate case, RP96-367, was filed with
the FERC in July 1997 and approved by the Commission on November 25, 1997. In
its approval, the FERC noted that the settlement not only eliminated the rate
increase in RP96-367 but reduced rates below the earlier RP95-409 level. Under
terms of the settlement, Williams cannot file for another general rate case
before December 31, 1999. In the six rate cases filed by Williams in the last
seven years, this is the first total settlement and avoids expensive and
protracted litigation of past and present issues.
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COST OF PURCHASED GAS
Cascade's cost of gas depends primarily on the prices negotiated with
producers and brokers, coupled with the cost of interstate and Canadian pipeline
transportation. Currently core gas prices are based 28% on firm or fixed
pricing and 72% on index based prices. This diversity, together with use of
storage volumes at a value determined at the time of injection, provides Cascade
with the ability to mitigate the effects of short term, unexpected spikes in the
market price of natural gas.
CURTAILMENT PROCEDURES
In previous heating seasons, cold weather has required Cascade to
significantly curtail deliveries to its interruptible customers. Cascade has not
curtailed any firm customers, except under force majeure provisions. Cascade's
tariffs effective in Washington and Oregon allow for curtailment of
interruptible services, which are provided at rates lower than for firm
services. In the event of curtailment by Cascade of firm service due to force
majeure, Cascade's tariffs provide that it shall not be liable for damages or
otherwise to any customer for failure to deliver gas curtailed in accordance
with the provisions of the tariffs. The tariffs provide for appropriate
adjustment of the monthly bill of firm customers curtailed by reason of an
insufficient supply of gas.
OREGON RATE SETTLEMENT
For a description of the settlement, effective September 1, 1997, of a
reduction of rates charged to customers in Oregon, see "Regulatory Matters"
under Item 7.
TERRITORY SERVED AND FRANCHISES
The population of communities served by Cascade totals approximately
744,000. Cascade has all the franchises necessary for the distribution of
natural gas in the communities it serves in Washington and Oregon. Under the
laws of those states, incorporated municipalities and counties may grant
non-exclusive franchises for a fixed term of years conferring upon the grantee
certain rights with respect to public streets and highways in the location,
construction, operation, maintenance and removal of gas distribution facilities.
In the opinion of Cascade's management, none of its franchises contain any
restrictions or requirements which are of a materially burdensome nature, and
such franchises are adequate for the conduct of Cascade's present business.
Franchises expire on various dates from 1998 to 2065. Management has not
incurred significant difficulties in renewing franchises when they expire and
does not expect any significant problems in the future.
CUSTOMERS
Residential and commercial customers principally use natural gas for space
heating and water heating. This market is very weather-sensitive. See
"Seasonality," below.
Agreements with Cascade's principal industrial customers are for fixed
terms of not less than one year and provide for automatic extension from year to
year unless terminated by either party on 30-days' notice.
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The principal industrial activities in Cascade's service area include the
production of pulp, paper and converted paper products, plywood, chemical
fertilizers, industrial chemicals, cement, clay and ceramic products, textiles,
refining of crude oil, producing and forming of aluminum, the processing and
canning of many types of vegetable, fruit and fish products, processing of milk
products, meat processing and the drying and curing of wood and agricultural
products.
SEASONALITY
Weather is an important factor affecting gas revenues because of the large
number of customers using gas for space heating. For the fiscal year ended
September 30, 1997, 67% of operating revenues and 102% of earnings from
operations were derived from the first two quarters (October 1996 through March
1997). Because of the seasonality of space heating revenues, Cascade believes
financial results for interim periods are not indicative of results to be
expected for the year.
COMPETITIVE CONDITIONS
Cascade operates in a competitive market for natural gas service. Cascade
competes with residual fuel oil and other alternative energy sources for
industrial boiler uses, and oil and electricity for residential and commercial
space heating, and electricity for water heating.
Competition is primarily based on price. For residential and commercial
space heating use, Cascade continues to maintain a price advantage over oil in
its entire service territory and has an advantage over electricity in the vast
majority of its territory. In the remaining areas of its service territory
served by public electric utilities with their own hydro power supply, Cascade
is almost equal in cost with respect to electricity furnished by those utilities
for space heating and water heating uses.
Historically, the large volume industrial market was very sensitive to
price fluctuations between the comparable cost of natural gas and alternate
fuels, principally residual fuel oil used in boiler applications. However, the
advent of open access transportation and the restructuring of gas supply and
contractual provisions with these customers has improved the Company's
competitive position. From December 1991 through January 1992 and again from
December 1992 through May 1994, except for a brief period in June 1993, residual
fuel oil prices were lower than natural gas, but Cascade did not experience any
significant loss of sales to alternate fuels during those periods.
In addition to multiple alternative fuels, the Company competes with other
sellers of natural gas because of the potential for bypass of the Company's
facilities. Bypass refers to actual or prospective customers which install
their own facilities and connect directly to an upstream pipeline and thereby
"bypass" the distribution company's service. The Company has experienced bypass
but has also experienced success in offering competitive rates to reduce
economic incentives to bypass.
The Bonneville Power Administration (BPA) is a major supplier of
hydro-electric power in the Pacific Northwest including Cascade's service area.
BPA significantly influences the electric rates of all classes of customers
including those applications in direct competition with natural gas marketed by
Cascade.
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ENVIRONMENTAL
The Company is subject to federal and state environmental regulation of its
operations and properties through the United States Environmental Protection
Agency, the Washington Department of Ecology and the Oregon Department of
Environmental Quality. Such regulation may, at times, result in the imposition
of liability or responsibility for the clean-up or treatment of existing
environmental problems or for the prevention of future environmental problems.
In the early 1950's, the Company acquired other corporations that owned
several of the gas distribution systems Cascade operates today. Among these
acquisitions, the Company has identified to date twelve small manufactured gas
plants which had used oil or coal as feedstock to produce manufactured gas.
Some of the waste byproducts of the manufacturing process contain hazardous
substances which, if found in sufficient concentrations, could pose
environmental problems.
Almost all of these plants were either dismantled or converted to propane
air prior to 1956. In 1956, when natural gas became available, the remaining
plants were dismantled. The plant sites were cleaned up when the plants were
dismantled and the sites are currently being used for other purposes.
Environmental agencies have monitored three of the plant sites and have found no
hazardous substances at levels requiring remediation.
During 1995, a claim related to environmental contamination from a former
manufactured gas plant site in Oregon, previously operated by a predecessor
corporation of the Company, was filed by the present property owner, which is a
municipal corporation. The claim requested that the Company assume
responsibility for investigation and possible cleanup of alleged contamination
on the property. The property owner and its consultants, working with the Oregon
Department of Environmental Quality (DEQ), have been in charge of the site
investigation and its pace. The original consultant's study was completed in
December 1995, and disclosed to the DEQ by the owner in January 1996. Since
August 1996, DEQ and the owner have been negotiating an intragovernmental
agreement for how the next steps in the site investigation will be administered.
At this date it appears that contamination is present at the site, but there is
no estimate of the extent of possible clean-up costs. Further, there has been no
agreement reached as to how such costs will be shared by the various parties. At
such time as the Company's obligation for remediation costs can be reasonably
estimated, accruals will be recorded and disclosures will be made in accordance
with applicable accounting standards. To the extent the Company may be
responsible for any portion of such costs, it intends to seek contribution from
other responsible parties, recovery from its insurers and appropriate rate
relief. See Note 10 under Notes to Consolidated Financial Statements.
As reported in the 10-Q report for the quarter ended March 31, 1997, the
Company has received notice of, and is investigating allegations of,
environmental contamination from a former manufactured gas plant site in
Washington previously operated by the Company. The Company has begun an
investigation, but has not yet determined the existence or extent of the alleged
contamination. To the extent the Company may be responsible for all or part of
the cost relating to such contamination, it expects to seek contribution from
other site owners and its insurers, and would seek appropriate rate relief to
the extent of remaining expense incurred. Based on information received to date,
the Company is not aware of hazardous substances present at any of the other
plant sites at levels that would require remediation.
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CAPITAL EXPENDITURES
Capital expenditures for fiscal 1998 are budgeted at $31.1 million.
Including the 1998 budget, the Company will have spent over $160,000,000 in new
plant in the five years ending in 1998, which is roughly equivalent to the
amount expended during the nine year period from 1985 through 1993. Capital
expenditures are primarily to expand the Company's distribution system to serve
its expanding customer base, as well as to increase deliverability on its
existing system to accommodate increased customer utilization.
The Company is currently forecasting that capital expenditures will total
approximately $150,000,000 over the next five years, reflecting expectations
that growth in the number of customers will continue at a pace similar to recent
experience.
NON-UTILITY SUBSIDIARIES
Cascade has four non-utility subsidiaries, only one of which is actively
engaged in business at present. This subsidiary is engaged in the servicing of
loans which were made to Cascade's gas customers to finance their purchases of
energy-efficient appliances. As of September 1997, the subsidiary no longer
makes new loans. The subsidiaries, which in the aggregate account for less than
1% of the consolidated assets of the Company, do not currently have a
significant impact on Cascade's financial statements.
PERSONNEL
At September 30, 1997, Cascade had 484 employees. Of the total employees,
217 are represented by the International Chemical Workers Union. The present
contract with the union extends to April 1, 1999, and thereafter until
terminated by either party on sixty days notice.
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Historical Summary of Operating Statistics
Fiscal Years Ended September 30
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
Natural Gas Deliveries to Customers
(thousands of therms)
Residential 110,137 101,779 93,524 83,912 86,284
Commercial 107,310 103,433 101,145 95,695 101,057
Industrial and other 851,357 834,363 768,537 666,698 507,957
----------- ----------- ----------- ----------- -----------
1,068,804 1,039,575 963,206 846,305 695,298
----------- ----------- ----------- ----------- -----------
Average Number of Customers
Residential 134,857 127,089 119,633 111,055 102,354
Commercial 24,682 23,741 22,755 21,794 20,968
Industrial and other 500 482 462 447 428
----------- ----------- ----------- ----------- -----------
160,039 151,312 142,850 133,296 123,750
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Total Customers at End of Year 160,247 152,116 143,372 134,823 124,963
Average Annual Therm Usage per Customer
Residential 817 801 782 756 843
Commercial 4,348 4,357 4,445 4,391 4,820
Industrial and other 1,702,714 1,731,044 1,663,500 1,491,494 1,186,815
Heating Degree Days (30-year avg. 5,675) 5,525 5,620 5,607 5,301 6,129
Daily Sendout (thousands of therms)
Peak day for the year 4,832 4,863 3,955 3,341 3,134
Average day for the year 2,928 2,840 2,639 2,319 1,905
Employees at End of Year 484 478 479 473 465
Customers Per Employee at End of Year 331 318 299 285 269
Capitalization Ratios at End of Year
Common shareholders' equity 44.3% 50.1% 39.6% 42.7% 46.7%
Preferred stock 2.6% 3.1% 3.3% 3.8% 4.5%
Long-term debt (incl. current maturities) 48.0% 46.8% 48.4% 41.4% 40.9%
Short-term debt 5.1% 0.0% 8.7% 12.1% 7.9%
----------- ----------- ----------- ----------- -----------
100.0% 100.0% 100.0% 100.0% 100.0%
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
</TABLE>
ITEM 2. PROPERTIES.
At September 30, 1997, Cascade's utility plant investments included
approximately 4,113 miles of distribution mains ranging in diameter from two
inches to sixteen inches, 240 miles of transmission mains ranging in diameter
from two inches to sixteen inches and 2,630 miles of service lines.
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The distribution and transmission mains are located under public property
such as streets and highways or on private property with the permission or
consent of the individual owner.
Cascade owns at present twenty-two buildings used for operations, office
space and warehousing in Washington and eight such buildings in Oregon. It
leases an additional five commercial offices. Cascade considers its properties
well maintained and in good operating condition, and adequate for Cascade's
present and anticipated needs. All facilities are substantially utilized.
ITEM 3. LEGAL PROCEEDINGS
See Item 1, Business, under "Environmental".
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The Executive Officers of the Company, as of December 1, 1997, are as follows:
<TABLE>
<CAPTION>
Year
Became
Name Office Age Officer
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
W. Brian Matsuyama Chairman of the Board and
Chief Executive Officer 51 1987
Ralph E. Boyd President and Chief
Operating Officer 60 1988
Jon T. Stoltz Senior Vice President -
Planning and Rates 50 1981
Larry E. Anderson Vice President -
Operations 49 1995
O. LeRoy Beaudry Vice President -
Consumer and Public Affairs 59 1981
King C. Oberg Vice President -
Gas Supply 56 1993
Larry C. Rosok Vice President - Human Resources,
and Corporate Secretary 41 1995
Calvin R. Steele Vice President -
Information Technology 58 1991
J. D. Wessling Vice President - Finance, and
Chief Financial Officer 54 1995
James E. Haug Controller and Chief
Accounting Officer 48 1981
</TABLE>
None of the above officers is related by blood, marriage or adoption to any
other of the above named officers. Except as discussed below, each of the above
named officers has been employed by the Company in a management capacity for at
least the past five years. None of the above officers hold directorships in
other public corporations. All officers serve at the pleasure of the Board of
Directors.
J. D. Wessling was employed by the Company on January 6, 1994 as
Director-Finance. From 1989 through 1993, he was chief financial officer for a
retail drug chain based in Phoenix, Arizona. From 1986 to 1989, he was chief
financial officer of a computer distribution company. Prior to that, Mr.
Wessling spent twelve years in the oil and gas industry, seven of which were
with Atlantic Richfield Company where he held various financial positions.
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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is traded on the New York Stock Exchange under the symbol
CGC. The following table states the per share high and low sales prices of the
Common Stock.
Fiscal 1997 Fiscal 1996
----------- -----------
Quarter High Low High Low
------- ---- --- ---- ---
December 31 17-1/2 15-5/8 17-3/8 14-5/8
March 31 17-1/8 15-3/8 16-5/8 15
June 30 17 15-1/4 16 13-3/8
September 30 17-11/16 15-7/8 16-1/2 13-3/4
At November 30, 1997, there were approximately 10,035 holders of the Common
Stock. The following table shows for the periods indicated the dividends paid
per share on the Common Stock.
Fiscal Fiscal
Quarter 1997 1996
------- ---- ----
December 31 $ 0.24 $ 0.24
March 31 $ 0.24 $ 0.24
June 30 $ 0.24 $ 0.24
September 30 $ 0.24 $ 0.24
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ITEM 6. SELECTED FINANCIAL DATA.
(dollars in thousands except per share data)
<TABLE>
<CAPTION>
Year Ended Nine Months
Sep 30 Ended Sep 30 Twelve Months Ended December 31
--------- -------------- -------------------------------------
1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
STATEMENTS OF OPERATIONS:
Operating Revenues 195,786 127,665 182,744 192,410 187,454
Less: Gas Purchases 104,342 69,679 102,858 118,083 113,500
Revenue Taxes 12,430 8,420 11,480 11,500 11,095
--------- --------- --------- --------- ---------
Operating Margin 79,014 49,566 68,406 62,827 62,859
--------- --------- --------- --------- ---------
Cost of Operations:
Operating expenses 35,670 25,058 30,818 30,202 27,856
Depreciation and amortization 13,416 9,362 11,733 10,921 9,964
Property and payroll taxes 3,989 3,181 4,051 4,039 3,757
--------- --------- --------- --------- ---------
53,075 37,601 46,602 45,162 41,577
--------- --------- --------- --------- ---------
Earnings From Operations 25,939 11,965 21,804 17,665 21,282
--------- --------- --------- --------- ---------
Nonoperating Expense (Income):
Interest 9,436 7,459 9,938 8,090 7,038
Interest charged to construction (532) (569) (394) (203) (323)
--------- --------- --------- --------- ---------
8,904 6,890 9,544 7,887 6,715
Amortization of debt issuance expense 612 459 606 593 562
Other (467) (2) (586) (80) (113)
--------- --------- --------- --------- ---------
9,049 7,347 9,564 8,400 7,164
--------- --------- --------- --------- ---------
Earnings Before Income Taxes
and Cumulative Effect of Change in
Accounting Method 16,890 4,618 12,240 9,265 14,118
Income Taxes 6,263 1,606 4,508 3,505 5,224
--------- --------- --------- --------- ---------
Earnings Before Cumulative
Effect of Change in Accounting Method 10,627 3,012 7,732 5,760 8,894
Cumulative effect of change in
accounting method - - - - 209
--------- --------- --------- --------- ---------
Net Earnings 10,627 3,012 7,732 5,760 9,103
Preferred Dividends 510 393 539 558 580
--------- --------- --------- --------- ---------
Net Earnings Available to
Common Shareholders $ 10,117 $ 2,619 $ 7,193 $ 5,202 $ 8,523
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Common Stock Outstanding
(thousands of shares):
End of year 10,967 10,787 9,144 8,912 8,566
Average 10,843 9,266 8,997 8,707 7,915
Earnings per Common Share
Before cumulative effect of change
in accounting method $ 0.93 $ 0.28 $ 0.80 $ 0.60 $ 1.05
Cumulative effect of change
in accounting method - - - - 0.03
--------- --------- --------- --------- ---------
Net Earnings per Common Share $ 0.93 $ 0.28 $ 0.80 $ 0.60 $ 1.08
--------- --------- --------- --------- ---------
</TABLE>
14
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA. (CONTINUED)
(dollars in thousands except per share data)
At September 30 At December 31
------------------------ ---------------------------------------
1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
RETAINED EARNINGS:
Beginning of the year $ 4,901 $ 9,297 $ 10,806 $ 14,076 $ 13,455
Net earnings available to
common shareholders 10,117 2,619 7,193 5,202 8,523
Common dividends (10,465) (7,015) (8,702) (8,472) (7,902)
----------- ----------- ----------- ----------- -----------
End of the year $ 4,553 $ 4,901 $ 9,297 $ 10,806 $ 14,076
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
CAPITAL STRUCTURE:
Common shareholders' equity $ 111,662 $ 109,126 $ 89,539 $ 87,710 $ 85,702
Redeemable preferred stocks 6,630 6,851 6,851 7,217 7,528
----------- ----------- ----------- ----------- -----------
Debt:
Long-term debt 121,150 101,850 102,100 100,000 87,000
Notes Payable and Commercial Paper 12,900 - 32,000 14,501 13,502
Current maturities of long-term debt - - - 5,000 -
----------- ----------- ----------- ----------- -----------
134,050 101,850 134,100 119,501 100,502
----------- ----------- ----------- ----------- -----------
Total capital $ 252,342 $ 217,827 $ 230,490 $ 214,428 $ 193,732
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
FINANCIAL RATIOS:
Return on common shareholders' equity 9.16% 7.88% 8.12% 6.00% 11.00%
Common stock dividend payout ratio 103% 257% 120% 161% 87%
Dividends declared per common share $ 0.96 $ 0.72 $ 0.96 $ 0.96 $ 0.94
Fixed charge coverage (before income tax deduction):
Times interest earned 2.68 2.17 2.16 2.07 2.86
Times interest and preferred
dividends earned 2.48 2.01 2.00 1.87 2.55
Book value per year-end share
of common stock $ 10.18 $ 10.12 $ 9.79 $ 9.84 $ 10.00
UTILITY PLANT:
Utility plant - end of year $ 416,365 $ 383,771 $ 362,924 $ 333,863 $ 310,288
Accumulated depreciation 160,332 147,599 138,831 127,806 117,925
----------- ----------- ----------- ----------- -----------
Net plant $ 256,033 $ 236,172 $ 224,093 $ 206,057 $ 192,363
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Construction expenditures, net
of contributions in aid $ 21,626 $ 26,053 $ 37,637 $ 27,251 $ 32,990
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Total assets $ 307,703 $ 296,381 $ 296,898 $ 273,090 $ 252,690
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
</TABLE>
15
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
The following is management's assessment of the Company's financial
condition and a discussion of the principal factors that affect consolidated
results of operations for the 12-month period ended September 30, 1997, and the
unaudited twelve month periods ended September 30, 1996, and 1995, and cash
flows for the 12-month period ended September 30, 1997, the nine-month
transition period ended September 30, 1996, and the year ended December 31,
1995. As of September 30, 1996, the Company adopted a fiscal year ending
September 30. Previously, the fiscal year coincided with the calendar year. The
new year end is more compatible with the Company's business cycle, and provides
for reporting of a heating season (October through March) in a single fiscal
year.
RESULTS OF OPERATIONS
Results of operations for the three fiscal periods were as follows:
<TABLE>
<CAPTION>
12 months ended September 30
(THOUSANDS EXCEPT PER SHARE DATA) 1997 1996* 1995*
------------------------------------------
<S> <C> <C> <C>
Operating Revenues $ 195,786 $ 184,572 $ 188,370
Less: Gas purchases 104,342 101,299 108,600
Revenue taxes 12,430 11,692 11,682
------------------------------------------
Operating Margin 79,014 71,581 68,088
------------------------------------------
Cost of Operations
Operating expenses 35,670 32,776 30,456
Depreciation and amortization 13,416 12,389 12,141
Property and payroll taxes 3,989 4,115 3,986
------------------------------------------
53,075 49,280 46,583
------------------------------------------
Earnings from operations 25,939 22,301 21,505
Nonoperating Expense (Income)
Interest 9,436 10,101 9,632
Interest charged to construction (532) (753) (292)
------------------------------------------
8,904 9,348 9,340
Amortization of debt issuance expense 612 612 603
Other (467) (142) (115)
------------------------------------------
9,049 9,818 9,828
------------------------------------------
Earnings Before Income Taxes 16,890 12,483 11,677
Income Taxes 6,263 4,272 4,590
------------------------------------------
Net Earnings 10,627 8,211 7,087
Preferred Dividends 510 524 544
------------------------------------------
Net Earnings Available to
Common Shareholders $ 10,117 $ 7,687 $ 6,543
Common Shares Outstanding:
Weighted average 10,843 9,204 8,936
End of period 10,967 10,787 9,098
Net Earnings per Common Share $ 0.93 $ 0.84 $ 0.73
*unaudited *unaudited
</TABLE>
16
<PAGE>
EARNINGS PER SHARE
Per share results for the 12 months ended September 30, 1997 were 10.7%
greater than the twelve months ended September 30, 1996. Earnings were affected
primarily by operating margins. In fiscal year 1997 earnings were reduced $.06
per share from gas cost increases in the state of Oregon. In fiscal year 1996
earnings were negatively affected $.10 per share due to a second-quarter (ended
June 30, 1996) charge against income for unrecovered gas costs and valuation
adjustments to non-utility assets.
OPERATING MARGIN
RESIDENTIAL AND COMMERCIAL MARGIN. Operating margins derived from sales to
residential and commercial customers were as set forth in the following table.
RESIDENTIAL AND COMMERCIAL OPERATING MARGINS
(DOLLARS IN THOUSANDS)
(12 MONTHS ENDED SEPTEMBER 30)
1997 1996 1995
- ----------------------------------------------------------------------------
DEGREE DAYS 5,525 5,620 5,607
AVERAGE NUMBER OF CUSTOMERS
Residential 134,857 127,089 119,633
Commercial 24,682 23,741 22,755
AVERAGE THERM USAGE PER CUSTOMER
Residential 817 801 782
Commercial 4,348 4,357 4,445
OPERATING MARGIN
Residential $ 29,725 $ 26,100 $ 23,586
Commercial $ 20,523 $ 19,794 $ 18,255
Fiscal 1997 operating margins from sales to residential and commercial
customers were up $4,355,000, or 9.5% over the twelve months ended September 30,
1996 (fiscal 1996). Factors contributing to this increase were customer growth,
higher therm usage per residential customer, and new state of Washington tariff
rates effective August 1, 1996. These factors resulted in margin increases of
approximately $2,426,000, $452,000 and $3,612,000, respectively. Somewhat
offsetting these increases were two factors. First, $1,652,000 of gas cost
increases were absorbed in the state of Oregon. Second, rates to Oregon
customers were decreased to recognize decreased property tax expense (see "Cost
of Operations"), reducing margins by approximately $470,000. Consumption per
customer is driven by the mix of customers, particularly in the commercial
class, the number and type of appliances used, and weather. Weather for 1997, as
measured by estimated degree days, was approximately 1.7% warmer than fiscal
1996.
Fiscal 1996 margins from residential and commercial customers increased by
$4,053,000 over the twelve months ended September 30, 1995 (fiscal 1995),
primarily due to 8,442 new customers, coupled with a moderate increase in the
average gas usage per residential customer.
17
<PAGE>
INDUSTRIAL AND OTHER MARGIN. The comparison of operating margin from
industrial and other customers is affected by the charge of $1,253,000, related
to unrecovered gas cost, recorded in the June 1996 quarter. Other than the
effect of this charge, margins increased by $1,826,000, or 6.8%, for fiscal
1997. These increases are primarily due to the addition of 20 new customers,
including service to a new cogeneration customer that began commercial operation
in June 1996.
Fiscal 1996 margins from industrial and other customers declined by
approximately $560,000 from fiscal 1995, due primarily to the 1996 charge
mentioned above. Other than this charge, margins increased by approximately
$693,000 attributable to the cogeneration customer that started in June 1996 and
another one that commenced June 1995.
COST OF OPERATIONS
Cost of operations consists of operating expenses, depreciation and
amortization, and property and payroll taxes. For the twelve-month periods ended
September 30, 1997, 1996, and 1995, these amounts were $53,075,000, $49,280,000,
and $46,583,000, respectively.
OPERATING EXPENSES for fiscal 1997, which are primarily labor and benefits
expenses, increased by $2,894,000, or 8.8%, over fiscal 1996. Of this
increase, $1,269,000 is attributable to deferred recognition of Postretirement
Benefits Other than Pensions (PBOP). From January 1993 through July 1996, a
portion of PBOP expenses were deferred, in accordance with a policy statement
issued by the Washington Utilities and Transportation Commission in 1992.
Concurrent with the settlement of the Washington rate case, effective August 1,
1996, ongoing PBOP expenses are no longer deferred, and amortization of the
previously deferred amounts is also included in operating expenses, resulting in
the expense increase. The new customer rates include recognition of this higher
level of PBOP expenses. Labor costs increased by $990,000, or 4.5%, related to
normal wage and salary rate adjustments, as well as to higher compensation
levels commensurate with a more highly skilled work force.
Fiscal 1996 expenses increased by $2,320,000 or 7.6% over fiscal 1995.
These increases were primarily attributable to payroll and benefit plan cost
increases, as well as additional costs related to the change in the Company's
fiscal year.
DEPRECIATION AND AMORTIZATION for fiscal 1997 increased by $1,027,000, or
8.3% over fiscal 1996, which is attributable to increases in depreciable utility
plant to serve a growing customer base.
PROPERTY AND PAYROLL TAXES for fiscal 1997 decreased by $126,000, or 3.1%,
compared to fiscal 1996. Higher property taxes related to increases in assets
are more than offset by reductions in Oregon tax rates resulting from a 1990
voter referendum. These Oregon rate reductions have no significant effect on net
earnings because the effect of reductions had previously been deferred in
accordance with the policy established by the Oregon Public Utility Commission.
These deferrals are currently being amortized, resulting in current recognition
of the effect of the reductions, and rates charged to Oregon customers have been
reduced accordingly (see "Operating Margin").
Increases in depreciation and amortization and in property and payroll
taxes in fiscal 1996 over fiscal 1995 are primarily due to increases in utility
plant.
18
<PAGE>
NONOPERATING EXPENSE (INCOME)
Interest expense decreased by $665,000 or 6.6% from fiscal 1996. This is
due to lower average amounts of short-term debt outstanding, and interest
accruals on deferred gas cost savings, partially offset by lower interest
accruals on deferred gas cost increases.
Other non-operating income increased by $325,000 to $467,000. The primary
factors resulting in this increase were a 1997 gain of $140,000 on the sale of a
parcel of land, compared to a 1996 charge of $311,000 relating to valuation
reserves against other assets. Additionally, there was less interest income in
fiscal 1997 because of fewer amounts of appliance loans outstanding.
INCOME TAXES
The increase in the provision for federal and state income taxes is
primarily attributable to the increase in pre-tax earnings.
LIQUIDITY AND CAPITAL RESOURCES
The seasonal nature of the Company's business creates short-term cash
requirements to finance customer accounts receivable and construction
expenditures. To provide working capital for these requirements, the Company has
a five-year credit commitment for $40 million from three banks. The committed
lines also support a money market facility of a similar amount and a regional
commercial paper program. A subsidiary company has a $5 million five-year
revolving credit facility used for non-regulated business, and at September 30,
1997, $1.15 million was outstanding. The Company also has $30 million of
uncommitted lines from three banks.
The balance of Medium-Term Notes at September 30, 1997 was $120 million.
There is remaining $30 million registered under the Securities Act of 1933 and
available for issuance. Because of the availability of short-term credit and the
ability to issue long-term debt and additional equity, management believes it
has adequate financial flexibility to meet its anticipated cash needs.
OPERATING ACTIVITIES
Operating activities resulted in a net cash flow of $46,000 for fiscal
1997, compared to $39,230,000 for the nine-month transition period ended
September 30, 1996, in spite of increased net earnings. The reduction is
primarily due to higher gas costs incurred during the 1996 - 1997 heating
season. For 1997, the cost of gas purchased exceeded the gas cost used to
establish the Company's sales tariffs, resulting in a negative cash flow of
$15,288,000. For the nine months ended September 30, 1996, the cost of gas was
less than the gas cost level established in the Company's sales tariffs,
resulting in a positive cash flow of $10,644,000. This represents a difference
of $25,932,000 between the two periods. The effect of these differences in gas
costs, except the Oregon amounts absorbed by the Company, as discussed above
under "Operating Margin", has been deferred, and thus had no effect on net
earnings. The Company will file for recovery of these deferred amounts from
customers through purchased gas rate adjustments over future periods. By the end
of fiscal 1997, gas costs returned to a level approximately equivalent to the
base cost level established in the Company's tariffs.
19
<PAGE>
Operating Activities were also affected by seasonal changes in accounts
receivable, accounts payable, accrued expenses, prepaid expenses, and other,
resulting in decreased cash flow of $21,775,000 from the nine-month transition
period ended September 30, 1996.
INVESTING ACTIVITIES
Cash used by investing activities in fiscal 1997 was $21,166,000, compared
to $25,208,000 for the 1996 transition period. The reduction in investing
activities is the result of an unusually high amount, $7,540,000, of customer
contributions in aid and advances for construction primarily related to
expenditures on a project completed in fiscal 1996. In the prior period, the
level of customer contributions in aid and advances for construction was a more
normal $405,000.
Budgeted capital expenditures for fiscal 1998 are approximately $31.1
million, which is expected to be financed approximately 50% from operating
activities, and 50% from a combination of debt and equity financing.
FINANCING ACTIVITIES
The principal financing activity for 1997 was the issuance of $20,000,000
of new medium-term notes, completed in September. In addition the Company raised
$1,747,000 of new equity capital through its dividend reinvestment program and
through sales of common stock to its 401(k) plan.
REGULATORY MATTERS
For the past seven years, the Company has been able to achieve normalized
results in Oregon greater than its allowed rate of return. Recognizing that the
limitations inherent in traditional utility regulation could, at some point,
inhibit further productivity improvements in that state, the Company has been
cooperatively exploring alternatives with the staff of the Oregon Public Utility
Commission. Ideally, both shareholders and customers should be able to benefit
fairly from efficiency gains. In September, 1997, the Company decreased Oregon
rates by $800,000 annually. The lower rates share with customers some of the
benefits of increased productivity and lower capital costs since the Company's
last general rate case in 1990, and can better serve as a starting point for new
methods it may develop for sharing future improvements. The new rates are
expected to reduce net income by $556,800 annually and to produce an implied
return on equity of 11.8% in Oregon.
ENVIRONMENTAL MATTERS
As reported in the Company's 10-Q reports for the quarters ended March 31
and June 30, 1997, the Company has received notice and is investigating
allegations of environmental contamination from a former manufactured gas plant
site in Washington previously operated by the Company. The Company has not yet
determined the existence or extent of the alleged contamination. To the extent
the Company may be responsible for all or part of the cost relating to such
contamination, it expects to seek contribution from other site owners and its
insurers, and would seek appropriate rate relief.
20
<PAGE>
CONTINGENT LIABILITIES
Like most entities that are heavily reliant on business application
computer software, the Company is affected by the fact that many of its computer
programs are not Year 2000 compliant. The result would be that in the year 2000,
the computer programs would not operate as intended.
The Company is currently in the process of identifying and correcting
computer programs which are not Year 2000 compliant. The implementation plan
will involve a combination of correcting existing program code, and acquiring
new programs to replace non-compliant programs. Much of this effort will
coincide with the Company's plan to upgrade its applications software over the
next few years. The conversion is not expected to have a material adverse effect
on the Company's results of operations, cash flows, or financial position.
FORWARD-LOOKING STATEMENTS
Statements contained in this report which are not historical in nature are
forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995. Forward-looking statements are subject to risks
and uncertainties that may cause actual future results to differ materially.
Such risks and uncertainties with respect to the Company include, among others,
its ability to successfully implement internal performance goals, competition
from alternative forms of energy, consolidation in the energy industry,
performance issues with key natural gas suppliers, the capital-intensive nature
of the Company's business, regulatory issues, including the need for adequate
and timely rate relief to recover increased capital and operating costs
resulting from customer growth and to sustain dividend levels, the weather,
increasing competition brought on by deregulation initiatives at the federal and
state regulatory levels, the potential loss of large volume industrial customers
due to "bypass" or the shift by such customers to special competitive contracts
at lower per unit margins, exposure to environmental cleanup requirements, and
economic conditions, particularly in the Company's service area.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
21
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS REPORT
Board of Directors
Cascade Natural Gas Corporation
Seattle, Washington
We have audited the accompanying consolidated balance sheets of Cascade Natural
Gas Corporation and subsidiaries (the Corporation) as of September 30, 1997 and
1996, and the related consolidated statements of net earnings available to
common shareholders, common shareholders' equity, and cash flows for the year
ended September 30, 1997, the nine months ended September 30, 1996, and the year
ended December 31, 1995. These financial statements are the responsibility of
the Corporation's management. Our responsibility is to express an opinion on
these 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Cascade Natural Gas Corporation and
subsidiaries as of September 30, 1997 and 1996, and the results of their
operations and their cash flows for the year ended September 30, 1997, the nine
months ended September 30, 1996, and the year ended December 31, 1995, in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Seattle, Washington
November 7, 1997
22
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF NET EARNINGS AVAILABLE TO COMMON SHAREHOLDERS
<TABLE>
<CAPTION>
(Dollars in thousands except per share data)
Year Ended Nine Months Ended Year Ended
September 30 September 30 December 31
1997 1996 1995
(Note 2)
<S> <C> <C> <C>
Operating Revenues $ 195,786 $ 127,665 $ 182,744
Less
Gas purchases 104,342 69,679 102,858
Revenue taxes 12,430 8,420 11,480
---------- ---------- ----------
Operating Margin 79,014 49,566 68,406
---------- ---------- ----------
Cost of Operations
Operating expenses 35,670 25,058 30,818
Depreciation and amortization 13,416 9,362 11,733
Property and payroll taxes 3,989 3,181 4,051
---------- ---------- ----------
53,075 37,601 46,602
---------- ---------- ----------
Earnings from operations 25,939 11,965 21,804
---------- ---------- ----------
Nonoperating Expense (Income)
Interest 9,436 7,459 9,938
Interest charged to construction (532) (569) (394)
---------- ---------- ----------
8,904 6,890 9,544
Amortization of debt issuance expense 612 459 606
Other (467) (2) (586)
---------- ---------- ----------
9,049 7,347 9,564
---------- ---------- ----------
Earnings Before Income Taxes 16,890 4,618 12,240
Income Taxes 6,263 1,606 4,508
---------- ---------- ----------
Net Earnings 10,627 3,012 7,732
Preferred Dividends 510 393 539
---------- ---------- ----------
Net Earnings Available to Common
Shareholders $ 10,117 $ 2,619 $ 7,193
---------- ---------- ----------
---------- ---------- ----------
Net Earnings Per Common Share $ 0.93 $ 0.28 $ 0.80
---------- ---------- ----------
---------- ---------- ----------
Average Shares Outstanding 10,843 9,266 8,997
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements
23
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
1997 1996
ASSETS (Dollars in thousands)
<S> <C> <C>
Utility Plant (Note 3) $ 416,365 $ 383,771
Less accumulated depreciation 160,332 147,599
----------- -----------
256,033 236,172
Construction work in progress 9,192 19,497
----------- -----------
265,225 255,669
----------- -----------
Other Assets
Investments in non utility property 668 667
Notes receivable, less current maturities 1,493 1,777
----------- -----------
2,161 2,444
----------- -----------
Current Assets
Cash and cash equivalents 3,162 543
Accounts receivable, less allowance of
$529 and $439 for doubtful accounts 11,865 11,646
Current maturities of notes receivable 536 631
Materials, supplies, and inventories 5,886 6,063
Prepaid expenses and other assets 7,382 5,723
----------- -----------
28,831 24,606
----------- -----------
Deferred Charges 11,486 13,662
----------- -----------
$ 307,703 $ 296,381
----------- -----------
----------- -----------
COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES
Common Shareholders' Equity
Common stock, par value $1 per share (Note 5)
Authorized, 15,000,000 shares; issued and
outstanding, 10,966,732 and 10,786,585 shares $ 10,967 $ 10,787
Additional paid-in capital 96,142 93,438
Retained earnings 4,553 4,901
----------- -----------
111,662 109,126
----------- -----------
Redeemable Preferred Stocks, aggregate redemption
amount of $6,845 and $7,097 (Note 4) 6,630 6,851
----------- -----------
Long-Term Debt (Note 7) 121,150 101,850
----------- -----------
Current Liabilities
Notes payable and commercial paper (Note 6) 12,900 -
Accounts payable 7,753 17,599
Property, payroll, and excise taxes 3,958 3,113
Dividends and interest payable 6,691 6,570
Other current liabilities 3,680 2,931
----------- -----------
34,982 30,213
----------- -----------
Deferred Credits and Other
Gas cost changes 6,290 21,578
Income taxes (Note 8) 16,080 16,184
Investment tax credits 2,764 3,031
Other 8,145 7,548
----------- -----------
33,279 48,341
----------- -----------
Commitments and Contingencies (Note 10) - -
----------- -----------
$ 307,703 $ 296,381
----------- -----------
----------- -----------
</TABLE>
The accompanying notes are an integral part of these financial statements
24
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Common Stock
(Dollars in thousands except per share data) ------------ Paid-In Retained
Shares Par Value Capital Earnings
------ --------- ------- --------
<S> <C> <C> <C> <C>
Balance, December 31, 1994 8,911,661 $ 8,912 $ 67,992 $ 10,806
Common stock issued:
Employee savings plan and
retirement trust (401(k)) 50,373 50 677
Director stock award plan 1,200 1 15
Dividend reinvestment plan 181,214 181 2,409
Redemption of preferred stock 5
Cash dividends:
Common stock, $.96 per share (8,702)
Preferred stock, senior, $.55 per share (68)
7.85% cumulative preferred stock,
$7.85 per share (471)
Net earnings 7,732
------------ ------------ ------------ ------------
Balance, December 31, 1995 9,144,448 9,144 71,098 9,297
Common stock issued:
Public offering 1,487,700 1,488 20,108
Employee savings plan and
retirement trust (401(k)) 33,893 34 492
Director stock award plan 1,800 2 26
Dividend reinvestment plan 118,744 119 1,714
Cash dividends:
Common stock, $.96 per share (7,015)
Preferred stock, senior, $.55 per share (40)
7.85% cumulative preferred stock,
$7.85 per share (353)
Net earnings 3,012
------------ ------------ ------------ ------------
Balance, September 30, 1996 10,786,585 10,787 93,438 4,901
Common stock issued:
Additional costs of 1996 public offering (34)
Employee savings plan and
retirement trust (401(k)) 51,834 52 794
Director stock award plan 3,688 4 54
Dividend reinvestment plan 124,625 124 1,887
Redemption of preferred stock 3
Cash dividends:
Common stock, $.96 per share (10,465)
Preferred stock, senior, $.55 per share (39)
7.85% cumulative preferred stock,
$7.85 per share (471)
Net earnings 10,627
------------ ------------ ------------ ------------
Balance, September 30, 1997 10,966,732 $ 10,967 $ 96,142 $ 4,553
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
</TABLE>
The accompanying notes are an integral part of these financial statements
25
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended Nine Months Ended Year Ended
September 30 September 30 December 31
1997 1996 1995
<S> <C> <C> <C>
Operating Activities
Net earnings $ 10,627 $ 3,012 $ 7,732
Adjustments to reconcile net earnings to
net cash provided by operating activities:
Depreciation and amortization 13,416 9,362 12,131
Write-down of assets - 154 -
Amortization of gas cost changes (2,473) 1,308 3,508
Increase (decrease) in deferred income taxes (105) (276) 1,079
Decrease in deferred investment tax credits (267) (175) (265)
Cash provided (used) by changes in operating assets and liabilities:
Accounts receivable (221) 14,835 2,400
Income taxes 1,183 (2,905) 105
Inventories 45 481 201
Gas cost changes (12,815) 9,336 2,226
Deferred items 1,710 4,345 (4,144)
Accounts payable and accrued expenses (8,115) 281 1,560
Prepaid expenses and other assets (2,858) (512) (1,111)
Other (81) (16) (399)
----------- ----------- -----------
Net cash provided by operating activities 46 39,230 25,023
----------- ----------- -----------
Investing Activities
Capital expenditures (29,166) (26,458) (38,486)
Customer contributions in aid of construction 7,540 405 849
New consumer loans (968) (666) (1,243)
Receipts on consumer loans 1,428 1,511 2,277
Purchase of securities available for sale - - (4,107)
Proceeds from securities available for sale - - 5,605
----------- ----------- -----------
Net cash used by investing activities (21,166) (25,208) (35,105)
----------- ----------- -----------
Financing Activities
Issuance of common stock 1,747 23,155 2,293
Redemption of preferred stock (216) - (362)
Proceeds from long-term debt, net 19,850 - 2,100
Repayment of long-term debt (700) (250) (5,000)
Changes in notes payable and commercial paper, net 12,900 (32,000) 17,499
Dividends paid (9,842) (6,581) (8,200)
----------- ----------- -----------
Net cash provided (used) by financing activities 23,739 (15,676) 8,330
----------- ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents 2,619 (1,654) (1,752)
Cash and Cash Equivalents
Beginning of year 543 2,197 3,949
----------- ----------- -----------
End of year $ 3,162 $ 543 $ 2,197
----------- ----------- -----------
----------- ----------- -----------
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 7,938 $ 6,890 $ 8,597
Income taxes $ 5,606 $ 1,606 $ 2,786
</TABLE>
The accompanying notes are an integral part of these financial statements
26
<PAGE>
Notes to Consolidated Financial Statements
NOTE 1 - NATURE OF BUSINESS
Cascade Natural Gas Corporation (the Company) is a local distribution company
(LDC) engaged in the distribution of natural gas. The Company's service
territory consists primarily of towns in Washington and Oregon, ranging from the
Canadian border in northwestern Washington to the Idaho border in eastern
Oregon.
As of September 30, 1997, the Company had approximately 160,000 core
customers and 162 non-core customers. Core customers are principally
residential and small commercial and industrial customers who take
traditional "bundled" natural gas service which includes supply, peaking
service, and upstream interstate pipeline transportation. Sales to core
customers account for approximately 22% of gas deliveries and 68% of
operating margin. The Company's sales to its core residential and commercial
customers are influenced by fluctuations in temperature, particularly during
the winter season. A warm winter season will tend to reduce gas consumption.
Over the longer term, these fluctuations tend to offset each other, as rates
charged to customers are developed based on the assumption of normal weather.
Non-core customers are generally large industrial and institutional customers
who have chosen "unbundled" service, meaning that they select from among several
supply and upstream pipeline transportation options, independent of the
Company's distribution service. The Company's margin from non-core customers is
generally derived only from this distribution service. The principal industrial
activities of its customers include the processing of forest products,
production of chemicals, refining of crude oil, production of aluminum,
generation of electricity, and processing of food.
The Company is subject to regulation of most aspects of its operations by the
Washington Utilities and Transportation Commission (WUTC) and the Oregon Public
Utility Commission (OPUC). It is subject to regulatory risk primarily with
respect to recovery of costs incurred. Various deferred charges and deferred
credits reflect assumptions regarding recovery of certain costs through
amortization during future periods.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company's accounting records and practices conform to the requirements and
uniform system of accounts prescribed by the WUTC and the OPUC.
Change in year end: Beginning in 1996, the Company changed its fiscal year end
to September 30 to include the fall-winter heating season within a single
financial reporting period. As a result of this change, the reporting period
for 1996, unless otherwise noted, is the nine month transition period ended
September 30, 1996. Because of the seasonal nature of the business, the period
ended September 30, 1996 is not indicative of a full year with respect to
operations and cash flow.
Principles of consolidation: The consolidated financial statements include the
accounts of Cascade Natural Gas Corporation and its wholly owned subsidiaries:
Cascade Land Leasing Co.; CGC Properties, Inc.; CGC Energy, Inc.; and CGC
Resources, Inc. All intercompany transactions have been eliminated in
consolidation.
Utility plant: Utility plant is stated at the historical cost of
construction or purchase. These costs include payroll-related costs such as
taxes and other employee benefits, general and administrative costs, and the
estimated cost of funds used during construction. Maintenance and repairs of
property, and replacements and renewals of items deemed to be less than units
of property, are charged to operations. Units of utility plant retired or
replaced are credited to property accounts at cost. Such amounts plus
removal expense, less salvage, are charged to accumulated depreciation. In
the case of a sale of non-depreciable property or major operating units, the
resulting gain or loss on the sale is included in other income or expense.
27
<PAGE>
Depreciation of utility plant is computed using the straight-line method. The
asset lives used for computing depreciation range from five to forty years,
and the weighted average annual depreciation rate is approximately 3.5%.
Investments: Investments consist primarily of real estate, classified as
nonutility property carried at the lower of cost or estimated net realizable
value.
Notes receivable: Notes receivable include loans made to customers for the
purchase of energy efficient appliances, which are generally the security for
the loan. Loans are made for a term of five years at interest rates varying
from 6.5% to 12%.
Materials, supplies and inventories: Materials and supplies for construction
and maintenance are recorded at cost. Inventories of natural gas are stated at
the lower of average cost or market.
Regulatory accounts: The Company's financial statements are prepared in
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation". This statement
provides for the deferral of certain costs and benefits which would otherwise be
recognized in revenue or expense, if it is probable that future rates will
result in recovery from customers or refund to customers of such amounts. A
regulated enterprise may prepare its financial statements according to the
provisions of SFAS No. 71 only as long as: (i) the enterprise's rates for
regulated services are established by or are subject to approval by an
independent third party regulator; (ii) the regulated rates are designed to
recover the enterprise's cost of providing the regulated services, and (iii) in
view of demand for the regulated services and the level of competition, it is
reasonable to assume that rates set at levels to recover the enterprise's costs
can be charged to and collected from customers. If at some point in the future,
the Company determines that all or a portion of the utility operations no longer
meets the criteria for continued application of SFAS No. 71, the Company would
be required to adopt the provisions of SFAS No. 101, "Regulated
Enterprises-Accounting for the Discontinuation of Application of FASB Statement
No. 71". Adoption of SFAS No. 101 would require the Company to write off the
regulatory assets and liabilities related to those operations not meeting the
criteria of SFAS No. 71.
Regulatory assets (liabilities) at September 30, 1997
and 1996 include the following:
(dollars in thousands) 1997 1996
- --------------------------------------------------------------------------
Unamortized loss on
reacquired debt $ 5,556 $ 6,086
Gas cost changes (6,290) (21,578)
Deferred income taxes (3,128) (3,279)
Postretirement benefits
other than pensions 3,936 4,685
Other, net 1,007 686
---------- ----------
Net $ 1,081 $(13,400)
---------- ----------
---------- ----------
Revenue recognition: The Company accrues estimated revenues for gas delivered
but not billed to residential and commercial customers from the meter reading
dates to month end.
Leases: The Company leases mainframe computer equipment and a majority of its
vehicle fleet. These leases are classified as operating leases. The Company's
primary obligation under these leases is for a twelve-month period, with options
to extend the lease thereafter. Commitments beyond one year are not material.
The Company has no capital leases.
Federal income taxes: The Company deducts depreciation computed on an
accelerated basis for federal income tax purposes, and as a result, deductions
exceed the amounts included in the financial statements.
28
<PAGE>
In 1981, the Company elected to record depreciation on 1981 and subsequent
utility plant additions under the Accelerated Cost Recovery System. This
election required the Company to provide deferred income taxes on the
difference between depreciation computed for financial statement and tax
reporting purposes beginning in 1981 (Note 8). This procedure has been
accepted by the WUTC and the OPUC. It is expected that any future increases
in federal income taxes resulting from the reversal of accelerated
depreciation on additions to utility plant in 1980 and prior will be allowed
in future rate determinations.
Investment tax credits: Investment tax credits were deferred and are amortized
over the life of the property giving rise to the credit.
Cash and cash equivalents: For purposes of reporting cash flows, the Company
accounts for all liquid investments, with a purchased maturity of three months
or less, as cash equivalents.
Use of estimates: The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates. The Company
has used significant estimates in measuring certain deferred charges and
deferred credits related to items subject to approval of the WUTC and the OPUC.
Significant estimates are also used in the development of discount rates and
trend rates related to the measurement of retirement benefit obligations and
accrual amounts, and in the determination of depreciable lives of utility plant.
New accounting standards: In February, 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards (FAS) No. 128, entitled
"EARNINGS PER SHARE" and FAS No. 129, entitled "DISCLOSURE OF INFORMATION ABOUT
CAPITAL STRUCTURE," which are effective for periods ending after December 15,
1997.
FAS No. 128 prescribes the method of calculating and reporting earnings per
share (EPS) amounts. It replaces the presentation of primary EPS with a
presentation of basic EPS. For entities with other than a simple capital
structure, it requires the dual presentation of basic and diluted EPS on the
face of the income statement. The Company does not expect implementation of
this standard to have a material effect on reported earnings per share.
FAS No. 129 establishes standards for disclosing information about the Company's
capital structure, including dividend and liquidation preferences, participation
rights, call prices and disclosure of the dates and the number of shares issued
upon conversion, exercise, or satisfaction of required conditions during at
least the most recent annual fiscal period and any subsequent interim period
presented. The Company does not expect implementation of this standard to have
a material effect on the reporting of the Company's capital structure.
In June, 1997, the Financial Accounting Standards Board issued FAS No. 130,
entitled "REPORTING COMPREHENSIVE INCOME," and FAS No. 131, entitled "DISCLOSURE
ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION," which are effective
for fiscal years beginning after December 15, 1997.
FAS No. 130 requires companies to (a) classify items of other comprehensive
income by their nature in a financial statement and (b) display the accumulated
balance of other comprehensive income separately from retained earnings and
additional paid-in-capital in the equity section of a statement of financial
position. The Company does not expect implementation of this standard to have a
material effect on the reporting of its financial information.
FAS No. 131 requires public enterprises to report financial and descriptive
information on the basis that is used internally for evaluating segment
performance and deciding how to allocate resources to segments. The Company
does not expect implementation of this standard to have a material effect on the
reporting of its financial information.
29
<PAGE>
NOTE 3 - UTILITY PLANT
Utility plant at September 30, 1997 and 1996 consists
of the following components:
(dollars in thousands) 1997 1996
- ------------------------------------------------------------------------
Distribution plant $ 363,275 $ 332,094
Transmission plant 14,086 14,086
Production plant 1,053 1,053
General plant 32,414 30,999
Intangible plant 212 212
Nondepreciable plant 5,325 5,327
------------ ------------
$ 416,365 $ 383,771
------------ ------------
NOTE 4 - REDEEMABLE PREFERRED STOCKS
Redeemable preferred stock at September 30, 1997 and 1996
consists of the following:
(dollars in thousands) 1997 1996
- --------------------------------------------------------------------------------
Shares Amount Shares Amount
7.85% cumulative, $1.00 par value 60,000 $ 6,000 60,000 $ 6,000
$.55 cumulative senior, series B
and C, without par value 71,750 630 96,560 851
---------------------- --------------------
131,750 $ 6,630 156,560 $ 6,851
---------------------- --------------------
The 7.85% cumulative preferred stock is subject to redemption in November, 1999.
The $.55 cumulative senior preferred stock is subject to minimum annual
redemption requirements, with Series B being fully redeemed in fiscal 1999, and
Series C in 2001. The shares may be purchased on the open market, or redeemed at
$10 per share plus accrued dividends. Redemption in excess of the required
number of shares of preferred stock can be made only if all cumulative dividends
on preferred stock have been paid. The aggregate annual preferred stock
redemption requirements for the next five years are set forth in the following
table:
Preferred stock redemption requirements
(dollars in thousands)
- ----------------------------------
Fiscal Shares Amount
1998 25,000 $ 250
1999 25,000 250
2000 74,500 6,145
2001 7,250 73
2002 - -
30
<PAGE>
NOTE 5 - COMMON STOCK
At September 30, 1997, shares of common stock are reserved for issuance as
follows:
Number
of shares
- ----------------------------------------------------------
Employee Savings Plan and
Retirement Trust (401(k) plan) 145,211
Dividend Reinvestment Plan 104,255
Director Stock Award Plan 4,112
------------
253,578
------------
The price of shares issued to the above plans is determined by the market price
of shares on the day of, or immediately preceding the issuance date.
In May 1993, the Company distributed to holders of Common Stock rights
("Rights") to purchase shares of Series Z Preferred Stock on the basis of one
Right for each share of Common Stock. The Rights may not be exercised and will
be attached to and trade with shares of Common Stock until the Distribution
Date, which will occur on the earlier of (i) the tenth day following a public
announcement that there has been a "Share Acquisition", i.e., that a person or
group (other than the Company and certain other persons) has acquired or
obtained the right to acquire 20% or more of the outstanding Common Stock and
(ii) the tenth business day following the commencement or announcement of
certain offers to acquire beneficial ownership of 30% or more of the
outstanding Common Stock. Subject to restrictions on exercisability while the
Rights are redeemable, each Right entitles the holder to buy from the Company
one one-hundredth of a share of Series Z Preferred Stock at a price of $85,
subject to adjustment. Upon the occurrence of a Share Acquisition, and provided
that all necessary regulatory approvals have been obtained, each Right will
thereafter entitle the holder (other than the acquiring person or group and
transferees) to buy from the Company for $85, shares of Common Stock having a
market value of $170, subject to adjustment.
NOTE 6 - NOTES PAYABLE AND COMMERCIAL PAPER
The Company's short-term borrowing needs are met with a $40,000,000 five year
revolving credit agreement with three of its banks. The annual commitment fee
is 1/8 of 1% and the committed lines of credit also support a money market
facility and a commercial paper facility of a similar amount. The Company also
has $30,000,000 of uncommitted lines from three banks. A subsidiary company
has a $5,000,000 revolving credit facility used for non-regulated business, and
at September 30, 1997, $1,150,000 was outstanding for a fixed term of five
years.
<TABLE>
<CAPTION>
September 30 December 31
(dollars in thousands) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amount outstanding $ 12,900 $ - $ 32,000
Average daily balance outstanding 13,666 15,664 13,170
Average interest rate, excluding commitment fee 5.94% 5.77% 6.29%
Maximum month end amount outstanding 21,650 27,500 32,000
</TABLE>
31
<PAGE>
NOTE 7 - LONG-TERM DEBT
Long -term debt at September 30, 1997 and 1996 consists of the following:
(dollars in thousands) 1997 1996
- ---------------------------------------------------
6.53% Five Year Term Note
due 2001 $ 1,150 $ 1,850
Medium-term notes:
5.77% due 1999 5,000 5,000
5.78% due 1999 5,000 5,000
7.18% due 2005 4,000 4,000
7.32% due 2004 22,000 22,000
8.38% due 2005 5,000 5,000
8.35% due 2005 5,000 5,000
8.50% due 2007 8,000 8,000
8.06% due 2012 14,000 14,000
8.10% due 2013 5,000 5,000
8.11% due 2013 3,000 3,000
7.95% due 2013 4,000 4,000
8.01% due 2013 10,000 10,000
7.95% due 2013 10,000 10,000
7.48% due 2027 20,000 -
------------ ------------
$ 121,150 $ 101,850
------------ ------------
None of the long-term debt includes sinking fund requirements, and there are no
current maturities at September 30, 1997. Annual obligations for redemption of
long-term debt are as follows: none in 1998, $10,000,000 in 1999, none in 2000,
$1,150,000 in 2001, none in 2002, and $110,000,000 thereafter.
Various debt and credit agreements restrict the Company and its subsidiaries as
to indebtedness, payment of cash dividends on common stock, and other matters.
Under these restrictions, approximately $25,756,000 is available for payment of
dividends as of September 30, 1997.
NOTE 8 - INCOME TAXES
Pursuant to the provisions of SFAS No. 109, the Company has recorded a deferred
tax liability for the cumulative tax effect of basis differences on utility
plant placed in service prior to 1981. Flow through accounting had previously
been recorded with respect to these temporary differences. In addition, the
Company has adjusted previously recorded deferred tax liabilities related to
plant placed in service after 1980, due to reductions in tax rates. Due to
regulatory policies regarding recovery of deferred taxes charged to customers
through rates, a regulatory liability was recorded which offsets the effect of
these adjustments to the deferred tax balances. Therefore these adjustments
have had no effect on net earnings. The provision for income tax expense
consists of the following:
(dollars in thousands) 1997 1996 1995
- ----------------------------------------------------------------------------
Current tax expense $6,785 $1,108 $2,661
Deferred tax expense (256) 673 2,112
Amortization of deferred
investment tax credits (266) (175) (265)
--------- ---------- ---------
$6,263 $1,606 $4,508
--------- ---------- ---------
32
<PAGE>
A reconciliation between income taxes calculated at the statutory federal tax
rate and income taxes reflected in the financial statements is as follows:
(dollars in thousands) 1997 1996 1995
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35% 35% 35%
Income tax calculated at statutory
federal rate $ 5,911 $ 1,616 $ 4,284
Increase (decrease) resulting from:
State income tax, net of federal tax benefit 122 34 86
Non-normalized depreciation differences 380 251 339
Amortization of investment tax credits (266) (175) (265)
Other 116 (120) 64
--------- --------- ----------
$ 6,263 $ 1,606 $ 4,508
--------- --------- ----------
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. The tax effects of
significant items comprising the Company's net deferred tax liability at
September 30, 1997 and 1996 are as follows:
(dollars in thousands) 1997 1996
- -----------------------------------------------------------------------
Deferred tax liabilities:
Basis differences on net fixed assets $ 14,230 $ 14,173
Debt refinancing costs 1,985 2,175
Retirement benefit obligations 986 1,066
----------- -----------
17,201 17,414
----------- -----------
Deferred tax assets:
Valuation reserves 458 363
Retirement benefit obligations 406 420
Provision for doubtful accounts 213 179
Other 44 268
----------- -----------
1,121 1,230
----------- -----------
Net deferred tax liability $ 16,080 $ 16,184
----------- -----------
NOTE 9 - RETIREMENT PLANS
The Company's noncontributory defined benefit pension plan covers substantially
all employees over 21 years of age with one year of service. The benefits are
based on a formula which includes credited years of service and the employee's
annual compensation. The Company's policy is generally to fund the plan to the
extent allowable under Internal Revenue Service rules. The Company provides
executive officers with supplemental retirement, death, and disability benefits.
Under the plan, vesting occurs on a stepped basis, with full vesting upon the
executive reaching age 55 and completing either five years of participation
under the plan or seventeen years of employment with the company, upon death, or
upon a change in control. The plan supplements the benefit received through
Social Security and the defined benefit pension plan so that the total
retirement benefits equal 70% of the executive's highest salary during any of
the five years preceding retirement. The plan also provides a death benefit
equivalent to ten years of vested benefits. The Company funds the plan by
making contributions to the Trust sufficient to assure assets held by the Trust
always exceed the accumulated benefit obligation for benefits payable by the
plan. The funded status of the defined benefit pension and supplemental
retirement plans and amounts recognized in the Company's financial statements
at September 30, 1997 and 1996 are set forth in the following table:
33
<PAGE>
<TABLE>
<CAPTION>
Supplemental
Pension Plan Retirement Plan
(dollars in thousands) 1997 1996 1997 1996
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Actuarial present value of accumulated
benefit obligations:
Vested $ 25,130 $ 21,960 $ 3,692 $ 2,875
Nonvested 767 208 465 219
--------------------------- ---------------------------
$ 25,897 $ 22,168 $ 4,157 $ 3,094
--------------------------- ---------------------------
--------------------------- ---------------------------
Projected benefit obligation for services
rendered to date $ (29,767) $ (25,837) $ (4,445) $ (3,636)
Plan assets, at fair value, primarily common stocks,
corporate bonds, and life insurance policies 29,158 21,432 4,888 4,131
--------------------------- ---------------------------
Projected benefit obligation (in excess of) less than plan assets (609) (4,405) 443 495
Unrecognized amounts:
Prior service cost 3,399 3,464 (223) (257)
Loss (gain) from past experience different
from that assumed (2,167) 871 1,082 704
Net transition obligation 13 18 927 1,028
Adjustment to recognize minimum liability - (684) - -
--------------------------- ---------------------------
Prepaid (accrued) pension cost $ 636 $ (736) $ 2,229 $ 1,970
--------------------------- ---------------------------
</TABLE>
Net pension cost for both plans included the following components:
<TABLE>
<CAPTION>
(dollars in thousands) 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost of benefits earned during the period $ 1,367 $ 1,095 $ 1,171
Interest cost on projected benefit obligation 2,398 1,684 1,936
Actual return on plan assets (6,771) (2,274) (4,057)
Deferral of unrecognized loss (gain) and
amortization, net 4,975 1,179 2,916
--------- --------- ----------
$ 1,969 $ 1,684 $ 1,966
--------- --------- ----------
</TABLE>
The following assumptions were used to determine the projected benefit
obligation and expected return on assets at September 30, 1997 and 1996, and
December 31, 1995:
September 30 December 31
1997 1996 1995
- --------------------------------------------------------------------------------
Pension plan:
Discount rate 7.75% 8.25% 7.25%
Long-term rate of return on plan assets 9.00% 9.00% 9.00%
Rate of increase in future compensation levels 5.00% 5.00% 5.00%
Supplemental retirement plan:
Discount rate 7.75% 8.25% 7.25%
Long-term rate of return on plan assets 8.50% 8.50% 8.50%
Rate of increase in future compensation levels 5.00% 5.00% 5.00%
401(k) PLAN. The Company has an Employee Savings Plan and Retirement Trust
(401(k) plan). All employees 21 years of age or older with one full year of
service are eligible to enroll in the plan. Under the terms of the plan, the
Company will match each employee's contribution at a rate of 75% of the
34
<PAGE>
employee's contribution up to 6% of the employee's compensation, as defined.
Prior to January 1, 1997, the matching rate was 50%. The increased contribution
is in the form of Company stock. The Company recognized costs for contributions
to this plan of $703,000, $377,000, and $458,000, for 1997, 1996 and 1995,
respectively.
RETIREE MEDICAL PLAN. The Company's health care plan provides Postretirement
Benefits Other than Pensions (PBOP), consisting of medical and prescription drug
benefits, to its retired employees hired prior to June 1, 1992, and their
eligible dependents. The Company has been recording PBOP expense, as provided
in SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than
Pensions", since January 1, 1993. The Company deferred the portion of the annual
PBOP accrual attributable to Washington regulated operations in excess of the
cash basis of recording these expenses through July 31, 1996. The amounts so
deferred were $767,000, and $1,028,000 in 1996 and 1995, respectively. On
August 1, 1996 new customer tariff rates were approved by the WUTC in the
general rate case. Accordingly, the PBOP deferrals ceased and the balance is
being amortized concurrently with the new rates.
Amounts accrued for PBOP, not including the above mentioned deferrals, consist
of the following components:
(dollars in thousands) 1997 1996 1995
- -------------------------------------------------------------------
Service cost $ 369 $ 326 $ 366
Net interest cost 1,211 939 1,114
Actual return on plan assets (1,417) (317) (627)
Net amortization and deferral 1,480 492 934
---------- ---------- ----------
$ 1,643 $ 1,440 $ 1,787
---------- ---------- ----------
The Company's policy is generally to fund the plan to the extent allowable under
Internal Revenue Service rules. The following table sets forth the health care
plan's funded status at September 30, 1997 and 1996:
(dollars in thousands) 1997 1996
- --------------------------------------------------------------------------
Accumulated postretirement
benefit obligation (APBO):
Retirees $ 5,814 $ 4,811
Fully eligible active plan participants 5,389 5,416
Other active plan participants 6,292 5,796
----------- -----------
17,495 16,023
Plan assets, at fair value, primarily common
stocks and corporate bonds 7,741 5,376
----------- -----------
Funded status (9,754) (10,647)
Unrecognized transition obligation 10,019 10,676
Unrecognized (gain) loss (1,976) (1,678)
----------- -----------
Accrued postretirement benefit cost $ (1,711) $ (1,649)
----------- -----------
At October 1, 1996, the per capita claims cost assumption was updated, resulting
in a 6.7% decrease in the APBO. For the valuation at September 30, 1997, the
discount rate was decreased from 8.25% to 7.75% and the census data was updated.
These, together with the passage of time, resulted in a 17.1% increase in the
APBO. In addition, plan assets increased substantially due to contributions to
the plan's assets, and returns on assets.
The assumed health care cost trend rate used in measuring the APBO is 9.0% for
1998, trending down to 5.5% at 2005. A one percentage point increase in the
assumed health care cost trend rate for each year
35
<PAGE>
would increase the APBO by approximately 15.2% and the service and interest cost
components of net postretirement health care cost by approximately 17.0%.
NOTE 10- COMMITMENTS AND CONTINGENCIES
Gas Service Contracts
The Company has entered into various transportation, supply, storage, and
peaking service contracts to assure that adequate supplies of gas will be
available to provide firm service to its core customers and to meet its
obligations under long-term non-core customer agreements, and to assure that
adequate capacity is available on interstate pipelines for the delivery of these
supplies. These contracts have maturities ranging from one to 26 years, and
generally provide for monthly and annual fixed demand charges and minimum
purchase obligations.
The Company's minimum obligations under these contracts are set forth in the
following table. The amounts are based on current contract price terms and
estimated commodity prices, which are subject to change:
Interstate Storage
Firm Gas Pipeline and Peaking
(dollars in thousands) Supply Transportation Service Total
- ------------------------------------------------------------------------------
1998 $ 29,445 $ 29,030 $ 5,604 $ 64,079
1999 16,483 28,893 3,903 49,279
2000 15,691 28,893 3,903 48,487
2001 12,633 28,893 4,165 45,691
2002 12,350 28,741 3,515 44,606
Thereafter 33,761 339,073 42,182 415,016
---------- ---------- --------- --------
$ 120,363 $ 483,523 $ 63,272 $667,158
---------- ---------- --------- --------
Purchases under these contracts for 1997, 1996, and 1995, including commodity
purchases, as well as demand charges have been as follows:
Interstate Storage
Firm Gas Pipeline and Peaking
(dollars in thousands) Supply Transportation Service Total
- ------------------------------------------------------------------------------
1997 $ 67,329 $ 30,547 $ 4,626 $ 102,502
1996 (nine months) $ 32,075 $ 19,002 $ 3,718 $ 54,795
1995 $ 45,223 $ 28,548 $ 4,722 $ 78,493
Environmental Matters
During the first quarter of 1995, a claim related to environmental contamination
from a manufactured gas plant site in Oregon previously operated by a
predecessor corporation of the Company was filed by the present property owner.
The claim requested that the Company assume responsibility for investigation and
possible cleanup of alleged contamination on the property. A consultant has
been retained by the property owner to evaluate the nature and extent of any
contamination. To date the consultant has reported that contamination
consistent with manufactured gas operations is present, but there is no estimate
of possible costs of remediation. To the extent the Company may be responsible
for all or part of such cost, it expects to seek contribution from other site
owners and its insurers, and would seek appropriate rate relief to the extent of
any remaining expense incurred.
36
<PAGE>
As reported in the 10-Q report for the quarter ended March 31, 1997, the Company
has received notice of, and is investigating allegations of, environmental
contamination from a former manufactured gas plant site in Washington previously
operated by the Company. The Company has begun an investigation, but has not yet
determined the existence or extent of the alleged contamination. To the extent
the Company may be responsible for all or part of the cost relating to such
contamination, it expects to seek contribution from other site owners and its
insurers, and would seek appropriate rate relief to the extent of remaining
expense incurred.
Litigation
Various lawsuits, claims, and contingent liabilities may arise from time to time
from the conduct of the Company's business. None of those now pending, in the
opinion of management, is expected to have a material effect on the Company's
financial position, results of operations, or liquidity.
Technology Risk
Like most entities that are heavily reliant on business application computer
software, the Company is affected by the fact that many of its computer programs
are not Year 2000 compliant. The result would be that in the year 2000, the
computer programs would not operate as intended.
The Company is currently in the process of identifying and correcting computer
programs which are not Year 2000 compliant. The implementation plan will involve
a combination of correcting existing program code, and acquiring new programs to
replace non compliant programs. Much of this effort will coincide with the
Company's plan to upgrade its applications software over the next few years. The
conversion is not expected to have a material adverse impact on the Company's
results of operations, cash flows, or financial position.
NOTE 11 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The following estimated fair value amounts have been determined by the Company,
using available market information and appropriate valuation methodologies.
However, considerable judgment is required in interpreting market data to
develop the estimates of fair value. Accordingly, these estimates are not
necessarily indicative of the amounts that the Company could realize in a
current market exchange. Thus, the use of different market assumptions or
estimation methodologies may have a material effect on the estimated fair value
amounts. The estimated fair values have been determined by using interest rates
that are currently available to the Company for issuance of instruments with
similar terms and remaining maturities. The estimated fair value amounts, at
September 30, 1997 and 1996, of financial instruments whose values are sensitive
to market conditions are set forth in the following table:
1997 1996
Carrying Estimated Carrying Estimated
(dollars in thousands) Amount Fair Value Amount Fair Value
- --------------------------------------------------------------------------------
Redeemable Preferred Stock $ 6,630 $ 6,815 $ 6,851 $ 6,757
Long-term Debt $ 121,150 $ 127,983 $ 101,850 $ 103,867
37
<PAGE>
NOTE 12 - INTERIM RESULTS OF OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
(thousands except Quarter Ended Quarter Ended
per share data) 9/30/97 6/30/97 3/31/97 12/31/96 9/30/96 6/30/96 3/31/96
- ---------------------------------------------------------------------------------------- ------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $25,911 $33,730 $71,174 $64,971 $26,584 $33,461 $67,620
Gas costs and revenue taxes 14,547 19,317 43,548 39,360 15,082 21,034 41,983
----------- ----------- ----------- ------------ ----------- ----------- ------------
Operating margin 11,364 14,413 27,626 25,611 11,502 12,427 25,637
Cost of operations 12,943 13,455 13,441 13,236 12,635 12,374 12,592
----------- ----------- ----------- ------------ ----------- ----------- ------------
Earnings (loss) from operations (1,579) 958 14,185 12,375 (1,133) 53 13,045
Interest and other, net 2,229 2,241 2,249 2,330 2,373 2,524 2,450
----------- ----------- ----------- ------------ ----------- ----------- ------------
Earnings (loss) before income taxes (3,808) (1,283) 11,936 10,045 (3,506) (2,471) 10,595
Income taxes (1,396) (274) 4,336 3,597 (1,504) (715) 3,825
----------- ----------- ----------- ------------ ----------- ----------- ------------
Net earnings (loss) (2,412) (1,009) 7,600 6,448 (2,002) (1,756) 6,770
Preferred dividends 126 128 128 128 131 131 131
----------- ----------- ----------- ------------ ----------- ----------- ------------
Net earnings (loss) available
to Common Shareholders ($2,538) ($1,137) $7,472 $6,320 ($2,133) ($1,887) $6,639
----------- ----------- ----------- ------------ ----------- ----------- ------------
Weighted average shares
outstanding 10,936 10,883 10,840 10,800 9,764 9,218 9,163
----------- ----------- ----------- ------------ ----------- ----------- ------------
Net earnings (loss) per share ($0.23) ($0.10) $0.69 $0.59 ($0.22) ($0.20) $0.72
----------- ----------- ----------- ------------ ----------- ----------- ------------
</TABLE>
38
<PAGE>
NOTE 13 - COMPARABLE PERIOD INFORMATION (UNAUDITED)
The following unaudited information on earnings and cash flows is presented to
provide financial information on periods comparable to those presented in the
audited financial statements. This information is taken from the books and
records of the Company and reflects all adjustments which are, in the opinion of
management, necessary for a fair statement of the results for the periods
presented.
CONSOLIDATED CONDENSED STATEMENTS OF NET EARNINGS
AVAILABLE TO COMMON SHAREHOLDERS
<TABLE>
<CAPTION>
Nine Months Nine Months Nine Months Twelve Months
Ended Ended Ended Ended
9/30/97 9/30/96 9/30/95 9/30/96
(Dollars in thousands except per share data)
(unaudited) (unaudited) (unaudited)
<S> <C> <C> <C> <C>
Operating Revenues $ 130,815 $ 127,665 $ 125,837 $ 184,572
Less
Gas purchases 68,653 69,679 71,238 101,299
Revenue taxes 8,759 8,420 8,208 11,692
------------ ------------ ------------ ------------
Operating Margin 53,403 49,566 46,391 71,581
------------ ------------ ------------ ------------
Cost of Operations
Operating expenses 26,685 25,058 23,470 32,776
Depreciation and amortization 10,193 9,362 8,273 12,389
Property and payroll taxes 2,961 3,181 3,116 4,115
------------ ------------ ------------ ------------
39,839 37,601 34,859 49,280
------------ ------------ ------------ ------------
Earnings from operations 13,564 11,965 11,532 22,301
------------ ------------ ------------ ------------
Interest and other deductions, net 6,719 7,347 7,157 9,818
------------ ------------ ------------ ------------
Earnings Before Income Taxes 6,845 4,618 4,375 12,483
Income Taxes 2,666 1,606 1,842 4,272
------------ ------------ ------------ ------------
Net Earnings 4,179 3,012 2,533 8,211
Preferred Dividends 382 393 408 524
------------ ------------ ------------ ------------
Net Earnings Available to
Common Shareholders $ 3,797 $ 2,619 $ 2,125 $ 7,687
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Net Earnings Per Common Share $ 0.35 $ 0.28 $ 0.24 $ 0.84
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
Average Shares Outstanding 10,871 9,266 8,977 9,204
------------ ------------ ------------ ------------
</TABLE>
39
<PAGE>
NOTE 13 - COMPARABLE PERIOD INFORMATION (UNAUDITED) - CONTINUED
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Nine Months Nine Months Nine Months Twelve Months
Ended Ended Ended Ended
9/30/97 9/30/96 9/30/95 9/30/96
(Dollars in thousands except per share data)
(unaudited) (unaudited) (unaudited)
<S> <C> <C> <C> <C>
Operating Activities
Net earnings $ 4,179 $ 3,012 $ 2,533 $ 8,211
Adjustments to reconcile net earnings to
net cash provided by operating activities:
Depreciation and amortization 10,193 9,362 8,998 12,496
Write-down of assets - 154 - 154
Amortization of gas cost changes (1,871) 1,308 2,520 1,691
Increase (decrease) in deferred income taxes 503 (276) 1,506 (703)
Decrease in deferred investment tax credits (209) (175) (180) (261)
Cash provided (used) by changes in operating assets and liabilities:
Current assets and liabilities (3,136) 12,180 7,239 8,098
Gas cost changes (7,772) 9,336 (1,740) 14,701
Other deferrals and non-current liabilities 873 4,329 (1,797) 788
---------- ---------- ---------- ----------
Net cash provided by operating activities 2,760 39,230 19,079 45,175
---------- ---------- ---------- ----------
Investing Activities
Capital expenditures (22,182) (26,458) (23,118) (41,730)
Customer contributions in aid of construction 1,565 405 532 624
New consumer loans (724) (666) (793) (1,116)
Receipts on consumer loans 1,162 1,511 1,492 2,297
Purchase of securities available for sale - - (1,813) (2,293)
Proceeds from securities available for sale - - 1,230 4,375
---------- ---------- ---------- ----------
Net cash used by investing activities (20,179) (25,208) (22,470) (37,843)
---------- ---------- ---------- ----------
Financing Activities
Issuance of common stock 1,465 23,155 1,821 23,625
Redemption of preferred stock - - (17) (345)
Proceeds from long-term debt, net 19,850 - - -
Repayment of long-term debt (400) (250) - (3,150)
Changes in notes payable and commercial paper, net 6,706 (32,000) 4,500 (19,001)
Dividends paid (7,399) (6,581) (6,144) (8,636)
---------- ---------- ---------- ----------
Net cash provided (used) by financing activities 20,222 (15,676) 160 (7,507)
---------- ---------- ---------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents 2,803 (1,654) (3,231) (175)
Cash and Cash Equivalents
Beginning of period 359 2,197 3,949 718
---------- ---------- ---------- ----------
End of period $ 3,162 $ 543 $ 718 $ 543
---------- ---------- ---------- ----------
</TABLE>
40
<PAGE>
INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES
Cascade Natural Gas Corporation
and Subsidiaries
We have audited the consolidated financial statements of Cascade Natural Gas
Corporation and subsidiaries as of September 30, 1997 and 1996, and for the year
ended September 30, 1997, the nine months ended September 30, 1996, and the year
ended December 31, 1995, and have issued our report thereon dated November 7,
1997; such consolidated financial statements and report are included in Part II
of this Annual Report on Form 10-K. Our audits also included the consolidated
financial statement schedule of Cascade Natural Gas Corporation, listed in Item
14(a)2. This consolidated financial statement schedule is the responsibility of
the Company's management. Our responsibility is to express an opinion based on
our audits. In our opinion, such consolidated financial statement schedule,
when considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information shown therein.
DELOITTE & TOUCHE LLP
Seattle, Washington
November 7, 1997
41
<PAGE>
SCHEDULE II
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
------------------------------
Additions
------------------------------
Balance at Charged to Charged to Balance at
Beginning Costs and Other Deductions End of
Description of Period Expenses Accounts (Note) Period
- --------------------- ---------------- ------------- --------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Allowance for Doubtful Accounts:
Year ended:
December 31, 1995 $461 330 366 $425
September 30, 1996 $425 440 426 $439
September 30, 1997 $439 507 417 $529
Note: Accounts receivable written off, net of recoveries
Valuation Reserve - Notes Receivable
December 31, 1995 $1,127 122 $1,249
September 30, 1996 $1,249 288 $1,537
September 30, 1997 $1,537 183 $1,720
Valuation Reserve - Investments
December 31, 1995 $150 0 $150
September 30, 1996 $150 154 304 $0
September 30, 1997 $0 $0
</TABLE>
42
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is directed to the information regarding directors under the
caption "Election of Directors" on pages 1 through 3 of the Proxy Statement
issued to Shareholders for the 1998 Annual Meeting (the 1998 Proxy Statement),
which information is incorporated herein by reference.
Under Section 16 of the Securities Exchange Act of 1934, holders of more
than 10 percent of the Common Stock and directors and certain officers of the
Company are required to file reports ("Section 16(a) Statements") of beneficial
ownership of Common Stock and changes in such ownership with the Securities and
Exchange Commission. The Company is required to identify in its proxy statements
those persons who to the Company's knowledge were required to file Section 16(a)
Statements and did not do so in a timely basis. Based solely on a review of
copies of Section 16(a) Statements furnished to the Company during and with
respect to its most recent fiscal year and on written representations from
reporting persons, the Company believes that each person who at any time during
the most recent fiscal year was a reporting person filed all required Section
16(a) Statements on a timely basis, except one report on Form 4 was filed late
for J. D. Wessling and for Thomas E. Cronin. The Report on Form 5 was filed
late for Ralph E. Boyd, Carl Burnham, Jr., Melvin C. Clapp, W. Brian Matsuyama,
Brooks G. Ragen, and Mary A. Williams.
ITEM 11. EXECUTIVE COMPENSATION
Reference is directed to the information regarding executive compensation
set forth in the 1998 Proxy Statement, under "Executive Compensation" on pages
7, 8, and 9, and under "Compensation Committee Interlocks and Insider
Participation" on page 9, which information is incorporated herein by reference.
Certain information concerning the executive officers of the Company is set
forth in Part I, under the caption "Executive Officers of the Registrant."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Reference is directed to the information regarding security ownership of
certain beneficial owners and management under the caption "Security Ownership
of Certain Beneficial Owners and Management" on page 4 of the 1998 Proxy
Statement (excluding the information under the subheading "Section 16(a)
Beneficial Ownership Reporting Compliance"), which information is incorporated
herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Reference is directed to the information regarding certain relationships
and transactions under the caption "Compensation Committee Interlocks and
Insider Participation" on page 9 of the 1998 Proxy Statement, which information
is incorporated herein by reference
43
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) 1. Financial Statements (Included in Part II of this report):
Independent Auditors' Report
Consolidated Statements of Net Earnings Available to Common
Shareholders or the Year Ended September 30, 1997, Nine Months
Ended September 30, 1996, and the Year Ended December 31, 1995
Consolidated Balance Sheets, September 30, 1997, and
September 30, 1996
Consolidated Statements of Common
Shareholders' Equity for the Year Ended September 30, 1997, Nine
Months Ended September 30, 1996, and the Year Ended
December 31, 1995
Consolidated Statements of Cash Flows for the Year Ended
September 30, 1997, Nine Months Ended September 30, 1996, and the
Year Ended December 31, 1995
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules (Included in Part II of this report):
Independent Auditors' Report on Financial Statement Schedule
Schedule II - Valuation and Qualifying Accounts
(a) 3. Exhibits:
Reference is directed to the index to exhibits following the signature
page of this report. Each management contract or compensatory plan or
arrangement required to be filed as an exhibit to this report is
identified in the list.
(b) Reports on Form 8-K:
None.
44
<PAGE>
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.
CASCADE NATURAL GAS CORPORATION
December 22, 1997 By /s/ J. D. Wessling
- ------------------------ --------------------
Date J. D. Wessling
Vice President - Finance, Chief
Financial Officer
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.
Chairman of the Board,
Chief Executive Officer
/s/ W. Brian Matsuyama and Director December 22, 1997
- -------------------------- (Principal Executive Officer) -----------------
W. Brian Matsuyama Date
President and
/s/ Ralph E. Boyd Chief Operating Officer December 22, 1997
- -------------------------- -----------------
Ralph E. Boyd Date
Vice President - Finance,
/s/ J. D. Wessling Chief Financial Officer December 22, 1997
- -------------------------- (Principal Financial Officer) -----------------
J. D. Wessling Date
Controller and Chief
/s/ James E. Haug Accounting Officer December 22, 1997
- -------------------------- (Principal Accounting Officer) -----------------
James E. Haug Date
/s/ Carl Burnham, Jr. Director December 22, 1997
- -------------------------- -----------------
Carl Burnham, Jr. Date
/s/ Melvin C. Clapp Director December 22, 1997
- -------------------------- -----------------
Melvin C. Clapp Date
/s/ Thomas E. Cronin Director December 22, 1997
- -------------------------- -----------------
Thomas E. Cronin Date
/s/ David A. Ederer Director December 22, 1997
- -------------------------- -----------------
David A. Ederer Date
/s/ Howard L. Hubbard Director December 22, 1997
- -------------------------- -----------------
Howard L. Hubbard Date
/s/ Larry L. Pinnt Director December 22, 1997
- -------------------------- -----------------
Larry L. Pinnt Date
/s/ Brooks G. Ragen Director December 22, 1997
- -------------------------- -----------------
Brooks G. Ragen Date
/s/ Mary A. Williams Director December 22, 1997
- -------------------------- -----------------
Mary A. Williams Date
45
<PAGE>
INDEX TO EXHIBITS
Exhibit
No. Description
- --- -----------
3.1 Restated Articles of Incorporation of the Registrant as amended
through March 28, 1996. Incorporated by reference to Exhibit 3.1 to
the Registrant's current report on Form 8-K dated July 18, 1996.
3.2 Restated Bylaws of the Registrant. Incorporated by reference to
Exhibit 3.2 to the Registrant's current report on Form 8-K dated July
18, 1996.
4.1 Indenture dated as of August 1, 1992, between the Registrant and The
Bank of New York relating to Medium-Term Notes. Incorporated by
reference to Exhibit 4 to the Registrant's current report on Form 8-K
dated August 12, 1992.
4.2 First Supplemental Indenture dated as of October 25, 1993, between the
Registrant and The Bank of New York relating to Medium-Term Notes.
Incorporated by reference to Exhibit 4 to the Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1993.
4.3 Rights Agreement dated as of March 19, 1993, between the Registrant
and Harris Trust and Savings Bank. Incorporated by reference to
Exhibit 2 to the Registrant's registration statement on Form 8-A dated
April 21, 1993.
4.4 First Amendment to Rights Agreement dated June 15, 1993, between the
Registrant and The Bank of New York. Incorporated by reference to
Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the
quarter ended June 30, 1993.
10.1 Letter Agreement dated April 28, 1995 between CanWest Gas Supply
U.S.A., Inc. and the Registrant for Winter Peaking Supply - 1995
through 1998. Incorporated by reference to Exhibit 10.1 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1995.
10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1)
dated January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.2 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1993 (1993 Form 10-K).
10.3 Service agreement (assigned Storage Gas Service under Rate
Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline
Corporation and the Registrant. Incorporated by reference to
Exhibit 10.3 to the Registrant's 1993 Form 10-K.
10.4 Service Agreement (Liquefaction -- Storage Gas Service under Rate
Schedule SGS-1) dated January 12,1994, between Northwest Pipeline
Corporation and the Registrant. Incorporated by reference to
Exhibit 10.4 to the Registrant's 1993 Form 10-K.
10.5 Gas Purchase Agreement dated November 1, 1990, between Mobil Oil
Canada and the Registrant. Incorporated by reference to Exhibit 10-6
to the 1991 Form 10-K.
10.6 Consent to Assignments, Dated June 1, 1997, which assigns from
Westcoast Gas Services Inc. (WGSI), to Engage Energy Canada, L.P.
(Engage) all the rights and obligations as specified in the contracts
contained herein as Exhibit Nos. 10.7, 10.9, and 10.22.
10.7 Amendment dated October 9, 1997 to Natural Gas Sales Agreement dated
November 1, 1990, between Canadian Hydrocarbons Marketing, Inc., and
the Registrant, as amended by the Consent
46
<PAGE>
to Assignments dated June 1, 1997. A PORTION OF THIS AGREEMENT IS
SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
10.9 Long Term Gas Sales Agreement dated August 26, 1993, between Canadian
Hydrocarbons Marketing Inc., and the Registrant, as amended by the
Consent to Assignments dated June 1, 1997. Incorporated by reference
to Exhibit 10.2 to amendment no. 1 to the Registrant's quarterly
report on Form 10-Q/A for the quarter ended September 30, 1993.
10.11 Gas transportation agreement between Pacific Gas Transmission Company
and the Registrant dated as of April 30, 1997.
10.12 Replacement Firm Transportation Agreement dated July 31, 1991, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10(1) to the 1992 Form S-2.
10.12.1 Amendments dated August 20, 1992, November 1, 1992, October 20, 1993,
and December 17, 1993, to Replacement Firm Transportation Agreement
dated July 31, 1991, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.12.1 to the
Registrant's 1993 Form 10-K.
10.13 Firm Transportation Service Agreement dated April 25, 1991, between
Pacific Gas Transmission Company and the Registrant (1993 expansion).
Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2.
10.14 Firm Transportation Service Agreement dated October 27, 1993, between
Pacific Gas Transmission Company and the Registrant. Incorporated by
reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K.
10.17 Storage Agreement dated July 23, 1990, between Washington Water Power
Company and the Registrant. Incorporated by reference to
Exhibit 10(v) to the 1992 Form S-2.
10.17.1 Second amendment to the agreement for the release of Jackson Prairie
Storage Capacity dated as of July 30, 1997, amending the Storage
Agreement dated July 23, 1990, between Washington Water Power Company
and the Registrant. Incorporated by reference to Exhibit 10.17.1 to
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1995.
10.18 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.18 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.
10.19 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated
January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.19 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.20 Service Agreement (Firm Redelivery Transportation Agreement under rate
Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.20 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.
10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources,
Inc. and the Registrant, as amended by Amended Exhibit A, effective
October 1, 1997. Incorporated by reference to Exhibit 10.21 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
47
<PAGE>
10.21.1 Amended Exhibit A, effective October 1, 1997, to Gas Purchase Contract
dated October 1, 1994, between IGI Resources, Inc. and the Registrant.
A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL
TREATMENT
10.22 Amended and restated Natural Gas Sales Agreement dated August 17,
1994, between Westcoast Gas Services, Inc. and Registrant which
replaces and substitutes for the Kingsgate Gas Sales Agreement dated
September 23, 1960, as amended by the Consent to Assignments dated
June 1, 1997, and the letter amendment dated October 8, 1997.
Incorporated by reference to Exhibit 10.22 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1994.
10.22.1 Letter amendment dated October 8, 1997, to Amended and restated
Natural Gas Sales Agreement dated August 17, 1994, between Westcoast
Gas Services, Inc. and Registrant which replaces and substitutes for
the Kingsgate Gas Sales Agreement dated September 23, 1961. A
PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL
TREATMENT
10.23 Firm Transportation Service Agreement dated November 4, 1994, between
Pacific Gas Transmission and the Registrant, effective
November 1, 1995. Incorporated by reference to Exhibit 10.23 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest
Pipeline Corporation and Registrant. Incorporated by reference to
Exhibit 10.24 to the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1994.
10.25 Prearranged Permanent Capacity Release of Firm Natural Gas
Transportation Agreements dated November 30, 1993 between Tenaska Gas
Co., Tenaska Washington Partners, L.P. and Registrant. Incorporated by
reference to Exhibit 10.25 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.
10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between
Tenaska Gas Co., Tenaska Washington Partners, L.P., and Registrant.
Incorporated by reference to Exhibit 10.26 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1994.
10.27 Agreement for Peaking Gas Supply Service dated November 22, 1991,
between Longview Fibre Company and Registrant, as amended by the
Amendment No. 3 to Agreement for Peaking Gas Service, dated as of
October 2, 1997. Incorporated by reference to Exhibit 10.27 to
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.27.1 Amendment No. 3 to Agreement for Peaking Gas Service, dated as of
October 2, 1997.
10.28 Letter Agreement dated October 24, 1995 between Westcoast Gas
Services, Inc. and the Registrant for Winter Peaking Supply - 1995
through 1998. Incorporated by reference to Exhibit 10.28 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1995.
10.29 1991 Director Stock Award Plan of the Registrant.* Incorporated by
reference to Exhibit 10(n) to the 1992 Form S-2.
10.30 Executive Supplemental Income Retirement Plan of the Registrant and
Supplemental Benefit Trust as amended and restated as of May 1, 1989,
as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by
reference to Exhibit 10(o) to the 1992 Form S-2.
10.31 Employment agreement between the Registrant and W. Brian Matsuyama.*
Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
10.32 Employment agreement between the Registrant and Jon T. Stoltz.*
Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2.
48
<PAGE>
12. Statement regarding computation of ratio of earnings to fixed charges
and preferred dividend requirements.
21. A list of the Registrant's subsidiaries is omitted because the
subsidiaries considered in the aggregate as a single subsidiary do not
constitute a significant subsidiary.
23. Consent of Deloitte & Touche LLP to the incorporation of their report
in the Registrant's registration statements.
27. Financial Data Schedule.
- ------------------------
* Management contract or compensatory plan or arrangement.
49
<PAGE>
EXHIBIT 10.6
CONSENT TO ASSIGNMENTS
DATED JUNE 1, 1997
In this document, "Agreements" means all natural gas, power marketing, energy
services, transportation, storage, or other form of merchant agreements or
transactions in effect as of June 1, 1997, between Westcoast Gas Services Inc.
(WGSI), and Cascade Natural Gas Corporation, (the "COMPANY") including without
limitation the agreements or transactions listed on the attached Schedule I.
Company hereby consents to the assignment and conveyance by WGSI of all of
WGSI's rights under the respective Agreements, and delegation by WGSI of all of
its obligations under the Agreements, to Engage Energy Canada, L.P. (Engage),
effective as of June 1, 1997.
Engage agrees that, on receipt of such assignment and delegation, from and after
June 1, 1997, it will assume all of WGSI's rights and obligations under the
Agreements. The Agreements so assigned to Engage shall remain in full force and
effect between Engage and the Company. Engage and Company hereby each ratify
and confirm the terms of the Agreements for all purposes, effective June 1,
1997.
This Consent document may be signed in any number of counterparts, and upon each
party having executed and delivered to Engage, and Engage having executed all of
those counterparts, all counterparts will have the same force and effect and if
all parties had executed and delivered the same Consent document.
ENGAGE ENERGY CANADA, L.P. CASCADE NATURAL GAS CORPORATION
By: By:
------------------------------ -------------------------
Name: Peter Leier Name:
-------------------------
Title: Vice President and General Counsel Title:
-------------------------
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Cascade Natural Gas Corp MERCHANT 1872 Gas Transaction 01-Jul-94 01-Jul-94 evergreen
Agreement
- -----------------------------------------------------------------------------------------------------------
Cascade Natural Gas Corp MERCHANT Gas Sales Agreement 17-Aug-94 17-Aug-94 31-Oct-04
(Kingsgate - 27,037
MMBtu/d)
- -----------------------------------------------------------------------------------------------------------
Cascade Natural Gas Corp MERCHANT 1934 Gas Sales Agreement 01-Nov-90 01-Nov-90 31-Oct-97
(Cascade #1 - 5,000
MMBtu/d)
- -----------------------------------------------------------------------------------------------------------
Cascade Natural Gas Corp MERCHANT 1958 Gas Sales Agreement 26-Aug-93 01-Nov-93 31-Oct-98
(Cascade #2 - 10,000
MMBtu/d)
- -----------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
[*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE
COMMISSION
EXHIBIT 10.7
October 9, 1997
CASCADE NATURAL GAS CORPORATION
222 Fairview Avenue North
Seattle, Washington
98109
ATTENTION: MS. MELISSA WHITTEN
- ----------------------------------
Dear Melissa:
RE: NATURAL GAS SALES AGREEMENT DATED NOVEMBER 1, 1990 AS AMENDED BETWEEN
BETWEEN ENGAGE ENERGY CANADA, L.P. (SUCCESSOR TO CANADIAN HYDROCARBONS
MARKETING INC./WESTCOAST GAS SERVICES INC.) ("ENGAGE")
AND CASCADE NATURAL GAS CORPORATION ("CASCADE")
- --------------------------------------------------------------------------------
Pursuant to Section 7.09 of the above noted agreement, this letter shall confirm
that the Gas Commodity Price and Reserves Standby Fee for the contract year
November 1, 1997 through October 31, 1998 be established as follows:
(a) GAS COMMODITY PRICE
(i) FOR THE PERIOD NOVEMBER 1, 1997 - DECEMBER 31, 1997
The Gas Commodity Price payable by Cascade per MMBtu of gas delivered
shall be U.S$[*]/MMBtu.
MINUS those related Westcoast Energy Inc. Demand Charges paid by
Cascade for the applicable contract month converted to U.S$/MMBtu
unit rate assuming a 100% load factor.
MINUS a Reserves Standby Charge credit of U.S$[*]/MMBtu.
(ii) FOR THE PERIOD JANUARY 1, 1998 - OCTOBER 31, 1998
The Gas Commodity Price payable by Cascade per MMBtu of gas delivered
shall be calculated monthly based upon the following:
The first of the month index as quoted in the publication "Inside
F.E.R.C.'s Gas Market Report, Price of Spot Gas Delivered in
Pipelines (MMBtu/day)" under the heading "Northwest Pipeline
Corporation-Canadian Border" Plus $[*] U.S/ MMBtu.
MINUS those related Westcoast Energy Inc. Demand Charges paid by
Cascade for the applicable contract month converted to U.S$/MMBtu
unit rate assuming a 100% load factor.
MINUS a Reserves Standby Charge credit of U.S$[*]/MMBtu.
<PAGE>
(b) RESERVES STANDBY FEE
The Reserves Standby Fee shall be rolled over at the existing fee
of U.S$[*]/MMBtu.
Please indicate your acceptance of the foregoing by signing both
copies of this letter and return one copy to us for our files.
If you require any further information please give me a call at
(403) 297-1838.
Yours truly,
ENGAGE ENERGY CANADA, L.P..
Jeff A. Thompson,
Vice President Supply and Marketing
British Columbia and Pacific Northwest Region
JAT/tw
c.c. Lydia Sloan
ACCEPTED AND AGREED TO this ______ day of ___________________,1997
CASCADE NATURAL GAS CORPORATION
Per:
------------------------
Title:
----------------------
<PAGE>
October 9, 1997
CASCADE NATURAL GAS CORPORATION
222 Fairview Avenue North
Seattle, Washington
98109
ATTENTION: MS. MELISSA WHITTEN
- ----------------------------------
Dear Melissa:
RE: (WGSI 5K AGREEMENT)
NATURAL GAS SALES AGREEMENT DATED NOVEMBER 1, 1990 AS AMENDED BETWEEN
BETWEEN ENGAGE ENERGY CANADA, L.P. (SUCCESSOR TO CANADIAN HYDROCARBONS
MARKETING INC./WESTCOAST GAS SERVICES INC.) ("ENGAGE")
AND CASCADE NATURAL GAS CORPORATION ("CASCADE")
- --------------------------------------------------------------------------------
Enclosed for signature are duplicate originals of the above noted agreement
amending Section 7.09 of the Gas Commodity Price for the period November 1, 1997
to October 31, 1998.
Please sign both copies and return one copy for our files.
If you require any further information please give me a call at (403) 297-1838.
Yours truly,
ENGAGE ENERGY CANADA, L.P..
Jeff A. Thompson,
Vice President Supply and Marketing
British Columbia and Pacific Northwest Region
Att.
JAT/tw
c.c. Lydia Sloan
<PAGE>
EXHIBIT 10.11
GAS TRANSPORTATION AGREEMENT
THIS AGREEMENT is made and entered into this 30th day of April, 1997, by and
between PACIFIC GAS TRANSMISSION COMPANY, a California Corporation (hereinafter
referred to as "PGT"),
and
CASCADE NATURAL GAS CORPORATION, a corporation existing under the laws of the
State of Washington (hereinafter referred to as "Shipper").
WHEREAS, PGT owns and operates a natural gas pipeline transmission
system which extends from a point of interconnection with the pipeline
facilities of Alberta Natural Gas Company Ltd. (ANG) at the International
Boundary near Kingsgate, British Columbia, through the states of Idaho,
Washington and Oregon to a point of interconnection with Pacific Gas and
Electric Company at the Oregon-California border near Malin, Oregon; and
WHEREAS, Shipper desires PGT, on an interruptible basis, to transport
certain quantities of natural gas as indicated in Exhibit A and
WHEREAS, PGT is willing to transport certain quantities of natural gas
for Shipper, on an interruptible basis,
NOW, THEREFORE, the parties agree as follows:
I
GOVERNMENTAL AUTHORITY
1.1 This Interruptible Transportation Agreement ("Agreement") is made
pursuant to the regulations of the Federal Energy Regulatory Commission (FERC)
contained in 18 CFR Part 284, Subpart G, as amended from time to time.
1.2 This Agreement is subject to all valid legislation with respect
to the subject matters hereof, either state or federal, and to all valid present
and future decisions, orders, rules, regulations and ordinances of all duly
constituted governmental authorities
<PAGE>
having jurisdiction.
1.3 Shipper shall reimburse PGT for any and all filing fees incurred
by PGT in seeking governmental authorization for the initiation, extension, or
termination of service under this Agreement and Rate Schedule ITS-1. Shipper
shall reimburse PGT for such fees at PGT's designated office within ten (10)
days of receipt of notice from PGT that such fees are due and payable.
Additionally, Shipper shall reimburse PGT for any and all penalty fees or fines
assessed PGT caused by the negligence of Shipper in not obtaining all proper
Canadian and domestic import/export licenses, surety bonds or any other
documents and approvals related to the Canadian exportation and subsequent
domestic importation of natural gas transported by PGT hereunder.
II
QUANTITY OF GAS AND PRIORITY OF SERVICE
2.1 Subject to the terms and provisions of this Agreement and PGT's
Transportation General Terms and Conditions applicable to Rate Schedule ITS-1,
daily receipts of gas by PGT from Shipper at the point(s) of receipt shall be
equal to daily deliveries of gas by PGT to Shipper at the point(s) of delivery;
provided, however, Shipper shall deliver to PGT an additional quantity of
natural gas at the point(s) of receipt as compressor station fuel, line loss and
unaccounted for gas as specified in the Exhibit A attached hereto. Any
limitations of the quantities to be received from each point of receipt and/or
delivered to each point of delivery shall be as specified on the Exhibit A
attached hereto. The service under this Agreement shall be conditioned upon the
availability of capacity sufficient to provide the service without detriment or
disadvantage to those customers of PGT that have a higher priority of service.
2.2 The maximum quantities of gas to be received for Shipper's
account at the point(s) of receipt and to be delivered by PGT to the point(s) of
delivery are set forth in Exhibit A.
2.3 In providing service to its existing or new customers, PGT will
use the priorities of service specified in Paragraph 18 of PGT's Transportation
General Terms and Conditions on file with the FERC.
2.4 Prior to initiation of service, Shipper shall provide PGT
with any information required by the FERC, as well as all information
identified in PGT's Transportation General Terms and Conditions applicable
to Rate Schedule ITS-1.
<PAGE>
III
TERM OF AGREEMENT
3.1 This Agreement shall become effective May 1, 1997, and shall
continue in full force and effect until May 1, 2007, and year to year thereafter
until canceled by ninety (90) day prior written notice given by either party to
the other.
IV
POINTS OF RECEIPT AND DELIVERY
4.1 The point(s) of receipt of gas deliveries to PGT is as designated
in Exhibit A, attached hereto.
4.2 The point(s) of delivery of gas to Shipper is as designated in
Exhibit A, attached hereto.
4.3 Shipper shall deliver or cause to be delivered to PGT the gas to
be transported hereunder at pressures sufficient to deliver such gas into PGT's
system at the point(s) of receipt. PGT shall deliver the gas to be transported
hereunder to or for the account of Shipper at the pressures existing in PGT's
system at the point(s) of delivery.
V
OPERATING PROCEDURES
5.1 Shipper shall conform to the operating procedures set forth in
PGT's Transportation General Terms and Conditions.
5.2 Nothing in Section 5.1 shall compel PGT to transport gas pursuant
to Shipper's request on any given day. PGT shall have the right to interrupt or
curtail the transport of gas for the account of Shipper pursuant to PGT's
Transportation General Terms and Conditions applicable to Rate Schedule ITS-1.
VI
RATE(S), RATE SCHEDULES,
AND GENERAL TERMS AND CONDITIONS OF SERVICE
6.1 Shipper shall pay PGT each month for services rendered pursuant
to this Agreement in accordance with PGT's Rate Schedule ITS-1, or
<PAGE>
superseding rate schedule(s), on file with and subject to the jurisdiction of
FERC. A summary of the transportation charges is provided on Exhibit A attached
hereto.
6.2 Shipper shall compensate PGT each month for compressor station
fuel, line loss and other unaccounted for gas associated with this
transportation service provided herein in accordance with PGT's Rate Schedule
ITS-1, or superseding rate schedule(s), on file with and subject to the
jurisdiction of FERC. A summary of the percentages of gas to be furnished by
Shipper for PGT's system fuel and losses is provided on Exhibit A attached
hereto.
6.3 This Agreement in all respects shall be and remains subject to
the applicable provisions of Rate Schedule ITS-1, or superseding rate
schedule(s) and of the applicable Transportation General Terms and Conditions of
PGT's FERC Gas Tariff Original Volume No. 1-A on file with the FERC, all of
which are by this reference made a part hereof.
6.4 PGT shall have the unilateral right from time to time to propose
and file with FERC such changes in the rates and charges applicable to
transportation services pursuant to this Agreement, the rate schedule(s) under
which this service is hereunder provided, or any provisions of PGT's
Transportation General Terms and Conditions applicable to such services.
Shipper shall have the right to protest any such changes proposed by PGT and to
exercise any other rights that Shipper may have with respect thereto.
VII
MISCELLANEOUS
7.1 This Agreement shall be interpreted according to the laws of the
State of California.
7.2 Shipper warrants that upstream and downstream transportation
arrangements are in place, or will be in place as of the requested effective
date of service, and that it has advised the upstream and downstream
transporters of the receipt and delivery points under this Agreement and any
quantity limitations for each point as specified on Exhibit A attached hereto.
7.3 Shipper agrees to indemnify and hold PGT harmless for refusal to
transport gas hereunder in the event any upstream or downstream transporter
fails to receive or deliver gas as contemplated by this Agreement.
1
<PAGE>
7.4 Unless herein provided to the contrary, any notice called for in
this Agreement shall be in writing and shall be considered as having been given
if delivered by registered mail or telex with all postage or charges prepaid, to
either PGT or Shipper at the place designated below. Routine communications,
including monthly statements and payment, shall be considered as duly delivered
when received by ordinary mail. Unless changed, the addresses of the parties
are as follows:
"PGT" PACIFIC GAS TRANSMISSION
2100 SW River Parkway
Portland, Oregon 97201
Attention: James E. Robbins
Manager, Gas Transportation & Services
"Shipper"
(Notices) CASCADE NATURAL GAS CORPORATION
222 Fairview Avenue N.
Seattle, WA 98109
Attention: Melissa Whitten
(Invoices) CASCADE NATURAL GAS CORPORATION
222 Fairvew Avenue N.
Seattle, WA 98109
Attention: King Oberg
7.5 A waiver by either party of any one or more defaults by the other
hereunder shall not operate as a waiver of any future default or defaults,
whether of a like or of a different character.
7.6 This Agreement may only be amended by an instrument in writing
executed by both parties hereto.
7.7 Nothing in this Agreement shall be deemed to create any rights or
obligations between the parties hereto after the expiration of the term set
forth herein, except that termination of this Agreement shall not relieve either
party of the obligation to correct any quantity imbalances or Shipper of the
obligation to pay any amounts due hereunder to PGT.
<PAGE>
7.8 Exhibit A attached hereto is incorporated herein by reference and
made a part hereof for all purposes.
IN WITNESS WHEREOF the parties hereto have caused this Agreement to be
executed as of the day and year first above written.
PACIFIC GAS TRANSMISSION COMPANY
By:
--------------------------
Name: James E. Robbins
Title: Manager, Gas Transportation & Services
CASCADE NATURAL GAS CORPORATION
Contract electronically signed on Pacific Trail-TM-
By: Mark Vaughan
Date signed: 04/30/1997
3
<PAGE>
EXHIBIT A
TO THE INTERRUPTIBLE TRANSPORTATION AGREEMENT
DATED APRIL 30, 1997, BETWEEN
PACIFIC GAS TRANSMISSION COMPANY
AND CASCADE NATURAL GAS CORPORATION (1)
MDQ Delivered (2)
Receipt Point Delivery Point Summer MMBtu/d Winter MMBtu/d
- ------------- -------------- -------------- --------------
Kingsgate, B.C. Moyie Springs, ID 50,000 50,000
Kingsgate, B.C. Bonner's Ferry, ID 50,000 50,000
Kingsgate, B.C. Schweitzer, ID 50,000 50,000
Kingsgate, B.C. Sandpoint, ID 50,000 50,000
Kingsgate, B.C. Athol, ID 50,000 50,000
Kingsgate, B.C. Rathdrum, ID 50,000 50,000
Kingsgate, B.C. Rathdrum CT, ID 50,000 50,000
Kingsgate, B.C. Spokane NPC, WA 50,000 50,000
Kingsgate, B.C. Spokane WWP, WA 50,000 50,000
Kingsgate, B.C. Mica, WA 50,000 50,000
Kingsgate, B.C. Spangle, WA 50,000 50,000
Kingsgate, B.C. Rosalia, WA 50,000 50,000
Kingsgate, B.C. St. John, WA 50,000 50,000
Kingsgate, B.C. Palouse, WA 50,000 50,000
Kingsgate, B.C. Lacrosse, WA 50,000 50,000
Kingsgate, B.C. Wallula, WA 50,000 50,000
Kingsgate, B.C. Kosmos Farm, OR 50,000 50,000
Kingsgate, B.C. Stanfield Exchange, OR 50,000 50,000
Kingsgate, B.C. Stanfield City Tap, OR 50,000 50,000
Kingsgate, B.C. South Hermiston, OR 50,000 50,000
Kingsgate, B.C. Coyote Springs, OR 50,000 50,000
Kingsgate, B.C. Boardman, OR 50,000 50,000
Kingsgate, B.C. Madras, OR 50,000 50,000
Kingsgate, B.C. Prineville, OR 50,000 50,000
Kingsgate, B.C. Redmond, OR 50,000 50,000
Kingsgate, B.C. Bend, OR 50,000 50,000
Kingsgate, B.C. South Bend, OR 50,000 50,000
Kingsgate, B.C. Stearns, OR 50,000 50,000
Kingsgate, B.C. LaPine,OR 50,000 50,000
Kingsgate, B.C. Gilchrist, OR 50,000 50,000
Kingsgate, B.C. Chemult, OR 50,000 50,000
Kingsgate, B.C. Diamond Junction, OR 50,000 50,000
Kingsgate, B.C. Klamath Falls, OR 50,000 50,000
Kingsgate, B.C. Medford, OR 50,000 50,000
Kingsgate, B.C. Tuscarora, OR 50,000 50,000
Kingsgate, B.C. Malin, OR 50,000 50,000
Spokane NPC, WA Kingsgate, B.C. 50,000 50,000
Spokane NPC, WA Stanfield Exchange, OR 50,000 50,000
<PAGE>
MDQ Delivered (2)
Receipt Point Delivery Point Summer MMBtu/d Winter MMBtu/d
- ------------- -------------- -------------- --------------
Spokane NPC, WA Tuscarora, OR 50,000 50,000
Spokane NPC, WA Malin, OR 50,000 50,000
Spokane WWP, WA Kingsgate, B.C. 50,000 50,000
Spokane WWP, WA Stanfield Exchange, OR 50,000 50,000
Spokane WWP, WA Tuscarora, OR 50,000 50,000
Spokane WWP, WA Malin, OR 50,000 50,000
Stanfield Exchange, OR Kingsgate, BC 50,000 50,000
Stanfield Exchange, OR Spokane NPC, WA 50,000 50,000
Stanfield Exchange, OR Spokane WWP, WA 50,000 50,000
Stanfield Exchange, OR Tuscarora, OR 50,000 50,000
Stanfield Exchange, OR Malin, OR 50,000 50,000
Tuscarora, OR Kingsgate, B.C. 50,000 50,000
Tuscarora, OR Spokane NPC, WA 50,000 50,000
Tuscarora, OR Spokane WWP, WA 50,000 50,000
Tuscarora, OR Stanfield Exchange, OR 50,000 50,000
Tuscarora, OR Malin, OR 50,000 50,000
Malin, OR Kingsgate, B.C. 50,000 50,000
Malin, OR Spokane NPC, WA 50,000 50,000
Malin, OR Spokane WWP, WA 50,000 50,000
Malin, OR Stanfield Exchange, OR 50,000 50,000
Malin, OR Stanfield City Tap, OR 50,000 50,000
Malin, OR Medford, OR 50,000 50,000
Malin, OR Tuscarora, OR 50,000 50,000
5
<PAGE>
EFFECTIVE MAY 1,1997
1) Rates for transportation service under this Agreement and gas to be
supplied by Shipper at Shipper's point(s) of receipt for fuels, line loss,
and unaccounted for purposes are listed in the Statement of Effective Rates
and Changes of PGT's FERC Gas Tariff, First Revised Volume 1-A, or
superseding tariff.
2) Total Maximum Daily Contract Quantity (delivered) not to exceed 50,000
MMBtu/d.
6
<PAGE>
EXHIBIT 10.17.1
SECOND AMENDMENT TO THE AGREEMENT FOR THE RELEASE
OF JACKSON PRAIRIE STORAGE CAPACITY
On this 30th day of July, 1997, The Washington Water Power Company ("Water
Power") and Cascade Natural Gas Corporation ("Cascade") (hereinafter
collectively referred to as the "Parties") have entered into this Agreement
("Second Amendment") for the purpose of amending the Agreement for the Release
of Jackson Prairie Storage Capacity ("Release Agreement") originally executed by
the Parties on July 23, 1990.
WITNESSETH:
WHEREAS, Water Power and Cascade are parties to a Release Agreement,
whereby Water Power will release a portion of its capacity and deliverability in
the Jackson Prairie Storage Project to Cascade, for a primary term ending
April 30, 1998; and
WHEREAS, Water Power and Cascade desire to extend the primary term of the
aforementioned Release Agreement to April 30, 2001, subject to the receipt of
necessary regulatory approvals;
NOW, THEREFORE, in consideration of their mutual covenants, the Parties
hereby agree to amend the Release Agreement in the following respects:
1. Section 4.1 of the Release Agreement, as previously amended, is hereby
revised to delete the references to "April 30, 1998" as the end of the primary
term of the Agreement, and substitute therefore the date of "April 30, 2001", so
that Section 4.1, as newly revised, reads as follows:
2.
4.1 Subject to the satisfaction of all conditions precedent,
including the receipt of necessary regulatory approvals, the primary
term of this Agreement shall continue until April 30, 2001, and
thereafter, on a year-to-year basis unless terminated by either Party
upon twelve (12) months' written notice of termination received prior
to April 30, 2001, or any anniversary thereafter.
1. Section 5.3 of the Release Agreement, as previously amended, is hereby
revised to delete the reference to "November 1, 1995" as the date by which all
conditions precedent must be satisfied, and to substitute therefore the date of
"November 1, 1998", so that Section 5.3, as newly revised, reads as follows:
2.
5.3 If all conditions precedent are not satisfied in time to
allow for Cascade's use of the released Deliverability and Capacity by
<PAGE>
November 1, 1998, either Party may, upon fifteen (15) day's written
notice, cancel this Agreement.
1. The Parties agree to substitute a revised version of the following
Exhibit, which was previously attached to the Release Agreement:
2.
Exhibit B: Consent of Northwest Pipeline and Puget Sound Energy
Company to the Release.
IN WITNESS WHEREOF each Party has caused this Second Amendment to be
executed under the hands of its duly authorized representative.
THE WASHINGTON WATER POWER CASCADE NATURAL GAS
COMPANY CORPORATION
By: /s/ By: /s/
--------------------------- ---------
Don Kopczynski Jon Stoltz
Manager, Resource Optimization Vice President,
Planning and Rates
<PAGE>
EXHIBIT 10.21.1
AMENDED
EXHIBIT "A"
To The
GAS PURCHASE CONTRACT
As Of: October 1, 1994
Between
CASCADE NATURAL GAS CORPORATION ("BUYER")
and
IGI RESOURCES, INC. ("SELLER")
Effective Date of this Exhibit "A": October 1, 1997
-------------------
Ending Date of this Exhibit "A": October 31, 1997
--------------------
DELIVERY POINT As defined in Section 1.01(g) of
the Contract noted above
MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446
DELIVERY POINT SELLING PRICE 1/
-------------
1. The Delivery Point Selling Price shall be equal to [*] plus the
actual cost of firm NOVA re-delivery service and firm ANG receipt
and re-delivery service plus any applicable allowance for
fuel-in-kind associated with such services.
"BUYER"
CASCADE NATURAL GAS CORPORATION
By:
--------------------------------
Name:
-------------------------------
Title:
------------------------------
"SELLER"
IGI RESOURCES, INC.
By:
---------------------------------
Randy Schultz
Executive Vice President
Chief Operating Officer
<PAGE>
[*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION
AMENDED
EXHIBIT "A"
To The
GAS PURCHASE CONTRACT
As Of: October 1, 1994
Between
CASCADE NATURAL GAS CORPORATION ("BUYER")
and
IGI RESOURCES, INC. ("SELLER")
Effective Date of this Exhibit "A": March 1, 1998
-----------------
Ending Date of this Exhibit "A": September 30, 1998
----------------------
DELIVERY POINT As defined in Section 1.01(g)
of the Contract noted above
MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446
DELIVERY POINT SELLING PRICE 1/
---------------
1. The Delivery Point Selling Price shall be equal to [*] plus the
actual cost of firm NOVA re-delivery service and firm ANG receipt
and re-delivery service plus any applicable allowance for
fuel-in-kind associated with such services.
"BUYER"
CASCADE NATURAL GAS CORPORATION
By:
--------------------------------
Name:
-------------------------------
Title:
------------------------------
"SELLER"
IGI RESOURCES, INC.
By:
---------------------------------
Randy Schultz
Executive Vice President
Chief Operating Officer
<PAGE>
[*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION
AMENDED
EXHIBIT "A"
To The
GAS PURCHASE CONTRACT
As Of: October 1, 1994
Between
CASCADE NATURAL GAS CORPORATION ("BUYER")
and
IGI RESOURCES, INC. ("SELLER")
Effective Date of this Exhibit "A": November 1, 1997
--------------------
Ending Date of this Exhibit "A": February 28, 1998
---------------------
DELIVERY POINT As defined in Section 1.01(g)
of the Contract noted above
MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446
DELIVERY POINT SELLING PRICE 1/
-----------------
1. The Delivery Point Selling Price shall be equal to [*]($[*] U.S. dry)
per MMBTU at AECO-C Hub plus the actual cost of firm NOVA re-delivery
service and firm ANG receipt and re-delivery service plus any
applicable allowance for fuel-in-kind associated with such services.
"BUYER"
CASCADE NATURAL GAS CORPORATION
By:
---------------------------------
Name:
-------------------------------
Title:
------------------------------
"SELLER"
IGI RESOURCES, INC.
By:
---------------------------------
Randy Schultz
Executive Vice President
Chief Operating Officer
<PAGE>
[*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION
EXHIBIT 10.22.1
VIA COURIER
October 8, 1997
CASCADE NATURAL GAS CORPORATION
222 Fairview Avenue North
Seattle, Washington
USA 98109
ATTENTION: MS. MELISSA WHITTEN
Dear Ms. Whitten:
RE: AMENDED AND RESTATED NATURAL GAS SALES AGREEMENT DATED AUGUST 17, 1994
BETWEEN ENGAGE ENERGY CANADA, L.P. ("ENGAGE") (SUCCESSOR TO WESTCOAST
GAS SERVICES INC.) ("SELLER") AND CASCADE NATURAL GAS CORPORATION
("BUYER") (THE "GAS SALES AGREEMENT")
- --------------------------------------------------------------------------------
This letter shall confirm the agreement between Engage and Cascade Natural Gas
Corporation ("Cascade") to amend Section 7.8 of the Gas Sales Agreement as
follows:
7.8 GAS COMMODITY PRICE
a. The Gas Commodity Price to be paid for gas delivered each month during
the period commencing on November 1, 1997 and expiring on October 31,
1998 shall be calculated as a percentage price determined under
Subsection c below, based upon a weighted average of the following
published prices (the "INDEX PRICE"):
(i) the "ROCKY MOUNTAIN" designated supply source into the
Northwest pipeline system, as that price is provided in
the publication entitled, "INSIDE F.E.R.C.'S GAS MARKET
REPORT" in the table entitled, "PRICES OF SPOT GAS
DELIVERED TO PIPELINES.......(per MMBtu dry), under the
"NORTHWEST PIPELINE CORP." entry multiplied by [*]%;
and
(ii) the "CANADIAN BORDER" designated supply source into the
Northwest pipeline system, as that price is provided in
the publication entitled, "INSIDE F.E.R.C.'S GAS MARKET
REPORT" in the table entitled, "PRICES OF SPOT GAS
DELIVERED TO PIPELINES.......(per MMBtu dry), under the
"NORTHWEST PIPELINE CORP" entry multiplied by [*]%; and
(iii) the "AECO "C" & N.I.T. ONE-MONTH SPOT" price as
published by the "CANADIAN GAS PRICE REPORTER" in the
table entitled, "CANADIAN NATURAL GAS SUPPLY PRICES"
under the column entitled "AVG" in U.S$/MMBtu
multiplied by [*]%.
b. The reference publication issue to determine the Gas Commodity Price
for a month shall be the first issue which is published after the
first day of the month.
<PAGE>
12/23/97 Cascade Natural Gas Corporation
Page 2
- --------------------------------------------------------------------------------
c. The percentage of the Index Price shall be determined based on the
quantity of gas purchased by Buyer under this Agreement during a
specified period, in accordance with the following table:
"INDEX PRICE" PERCENTAGE TABLE
Period Quantity of Gas Purchased Applicable Percentage
During Period of "Index Price"
- --------------- ------------------------- ---------------------
Nov. 1, 1997 to 0 to 4,136,661 [*]%
Oct. 31, 1998 4,136,662 to 7,029,620 [*]%
7,029,621 to 9,868,505 [*]%
Engage and Cascade further agree that "Exchange Rate" shall mean the thirty (30)
day average of the daily spot exchange rate, expressed as U.S$/Cdn.$1.00, and
that this definition shall supersede the definition provided in subclause 1.1y
of the Gas Sales Agreement.
Terms or phrases defined or used in the Gas Sales Agreement shall have the same
meaning herein unless specifically stated otherwise.
Please indicate your agreement with the foregoing by signing both copies of this
letter in the space provided below. Please retain one copy for your files and
return the other copy to Engage at your earliest convenience.
Yours truly,
ENGAGE ENERGY CANADA, L.P.
Jeff Thompson,
Vice President, Supply and Marketing
British Columbia and Pacific Northwest Region
JAT/tw
c.c. Lydia Sloan
ACCEPTED AND AGREED TO THIS DAY OF , 1997.
------- -----------------------
CASCADE NATURAL GAS CORPORATION
Per:
-------------------------
Title:
-----------------------
<PAGE>
12/23/97 Cascade Natural Gas Corporation
Page 3
- --------------------------------------------------------------------------------
VIA COURIER
October 8, 1997
CASCADE NATURAL GAS CORPORATION
222 Fairview Avenue North
Seattle, Washington
98109
ATTENTION: MS. MELISSA WHITTEN
- ----------------------------------
Dear Ms. Whitten:
RE: AMENDED AND RESTATED NATURAL GAS SALES AGREEMENT DATED AUGUST 17, 1994
BETWEEN ENGAGE ENERGY CANADA, L.P. ("ENGAGE") (SUCCESSOR TO WESTCOAST
GAS SERVICES INC.) ("SELLER") AND CASCADE NATURAL GAS CORPORATION
("BUYER") (THE "GAS SALES AGREEMENT")
(KINGSGATE AGREEMENT)
- --------------------------------------------------------------------------------
Enclosed for signature are duplicate originals of the above noted agreement
extending the Gas Commodity Price under Section 7.8 for an additional one year
term.
Please sign both copies and return one for our files.
If you have any questions please give me a call at (403) 297-1838.
Yours truly,
ENGAGE ENERGY CANADA, L.P.
Jeff Thompson,
Vice President, Supply and Marketing
British Columbia and Pacific Northwest Region
Att.
JAT/tw
c.c. Lydia Sloan
<PAGE>
EXHIBIT 10.27.1
SETTLEMENT AGREEMENT
OCTOBER 2, 1997
The undersigned, Longview Fibre Company ("Fibre") and Cascade Natural
Gas Corporation ("Cascade"), are parties to the Agreement for Peaking Gas
Service dated as of March 22, 1991 ("PGS Agreement"). The parties have
disagreed over the amount properly payable by Cascade to Fibre for service under
the PGS Agreement for the period beginning October 1, 1996.
In the interest of compromise and settlement, the parties have entered
into this Settlement Agreement to resolve their differences without need for
arbitration or litigation. This Settlement Agreement is a compromise reached
between the parties after negotiation relating to pricing to the service
rendered and to be rendered by Fibre to Cascade under the PGS Agreement. The
applicable period of agreement for the PGS Fee is from October 1996, to
September 30, 2001.
The parties agree as follows:
1. The settlement proposal of Fibre to Cascade contained in its
September 4, 1997, letter, a copy of which is attached hereto as Exhibit A and
incorporated herein by this reference, is agreed to by the parties with one
correction. On page 2, next to last paragraph, the ending time for the reduced
PGS fee is to be the Contract Year October 2000 to September 2001. This
correction is noted on Exhibit A.
2. In order to implement this agreement, the PGS Agreement will be
amended in the form attached as Exhibit B.
This Settlement Agreement is entered into as of the date first set
forth above.
LONGVIEW FIBRE COMPANY CASCADE NATURAL GAS
CORPORATION
By
------------------------
Its By
--------------------- ------------------------------
King C. Oberg
Vice President - Gas Supply
<PAGE>
AMENDMENT NO. 3 TO AGREEMENT FOR
PEAKING GAS SERVICE (PGS)
OCTOBER 2, 1997
This Amendment No. 3 is dated as of October 2, 1997, by and between
Cascade Natural Gas Corporation ("Cascade") and Longview Fibre Company
("Longview").
WHEREAS, Cascade and Longview executed an Agreement For Peaking Gas
Service (PGS) ("Agreement") dated as of November 22, 1991, and
WHEREAS, Cascade and Longview desire to amend the Agreement,
NOW, THEREFORE, for good and valuable consideration, the receipt of
which is hereby acknowledged, it is agreed as follows:
1. Section 4 of the Agreement shall be amended to add the following:
PROVIDED, HOWEVER, that pursuant to a Settlement Agreement dated
October 2, 1997, the parties have agreed that the PGS Fee for the period
starting with the Contract Year October 1996 to September 1997, and ending with
the Contract Year October 2000 to September 2001, the PGS Fee shall be
$708,984.44 per year. The parties also agree to renegotiate the PGS Fee in good
faith in the event of a material gas and/or transportation rate increase with
respect to Cascade's Washington Water Power Storage Agreement.
As additional consideration for this Agreement, Cascade shall
provide Longview with the following fuel management services for
the remaining term of the Agreement:
a. an aggressive program, with daily consultations between
Cascade and Longview, to release any part of the 48,000 dt/day of
capacity on Northwest Pipeline for which Longview currently pays
the reservation fees and which is not needed by Longview, with the
proceeds from such releases going to Longview;
b. an aggressive program, with daily consultations between
Cascade and Longview, to resale any part of the 18,000 dt/day of
natural gas (or additional supplies purchased by Longview) which
Longview currently buys from Duke or other supplier and which is
not needed by Longview, with the revenue from
<PAGE>
such resale going to Longview;
c. an aggressive program, with daily consultations between
Cascade and Longview, to purchase gas at locations agreed to by
Cascade and Longview and to have such gas delivered to Longview;
d. monthly reporting of the savings to Longview under the
above-stated programs; and
e. monthly balancing and reporting of all gas and
transportation activities related to Longview.
2. Capitalized terms used in this Amendment shall have the meanings
as defined in the Agreement.
3. Except as modified by the foregoing amendment, the Agreement, as
amended to date, shall remain in full force and effect in accordance with its
terms.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No.
3 to be duly executed in counterparts by their duly authorized representatives
as of the date first above written.
CASCADE NATURAL GAS CORPORATION LONGVIEW FIBRE COMPANY
By By
---------------------------- -----------------------------
King C. Oberg Its
Vice President, Gas Supply ----------------
<PAGE>
September 4, 1997
Mr. King Oberg PRIVILEGED AND
Vice President, Gas Supply CONFIDENTIAL;
Cascade Natural Gas Corporation FOR SETTLEMENT PURPOSES
222 Fairview Avenue North ONLY
Seattle, WA 98109
Dear King:
This letter is in response to (1) the proposal of Cascade Natural Gas
("Cascade") to adjust the annual fee under the Agreement for Peaking Gas Service
("PGS") between Longview Fibre Company ("Fibre") and Cascade from $970,350.00 to
$708,894.44 beginning the October 1996 to September 1997 period, and (2) your
August 8 reply to our letter expressing concerns with your proposal.
At the outset, Fibre must respectfully point out that the storage service is not
comparable to the PGS. Although Cascade can change the scheduled quantity for
withdrawals from storage up to four times per day, Cascade can make up to 6
changes (initiating or terminating) and up to 12 changes (rate of taking) per
day under the PGS. Moreover, in order to effect delivery of the storage gas to
the city gate, Cascade must comply with the transportation nomination procedures
of Northwest, which in all cases do not assure that Cascade can arrange for
delivery of the storage gas on 4 hours' notice or change the rate of delivery of
the storage gas on 2 hours' notice as Cascade can under the PGS. The 4-hour and
2-hour notice provisions of the PGS are features that Fibre does not believe can
be duplicated by other alternative peaking services, especially not the storage
service obtained by Cascade.
Furthermore, Fibre respectfully disagrees with the methodology used in Cascade's
proposal. Under the Agreement for PGS, the annual fee is adjusted "to ensure
the PGS fee is COMPARABLE to the least cost alternative sources of peaking
service reasonably available to Cascade." As set forth in detail below, Fibre
does
<PAGE>
not believe that the $708,894.44 figure proposed by Cascade represents a
comparable level of the full costs to Cascade for the storage service received
through Washington Water Power.
First, once Cascade withdraws 192,000 dekatherms of its gas in storage, Cascade
can no longer receive 15, 000 dt/day of gas as it does under the PGS. To adjust
the features of the storage service to make them comparable to the PGS, Cascade
would have to either (1) obtain 405,000 additional dekatherms of annual storage
service, or (2) inject quantities into storage during the winter season. Fibre
believes that the first option would increase Cascade's storage costs by at
least $588,912.00 per year, while the second option would increase the costs by
at least $229,608.00 per year.
Second, under the storage service, Cascade incurs a cost of carrying the gas
held in storage until it is delivered. Fibre calculates this cost to be at
least $43,815.67 per year.
Third, Fibre believes that the cost to Cascade of the fuel charges for storage
withdrawals and in transporting gas from storage were omitted. Fibre calculates
these charges to be at least $23,066.44 per year.
Fourth, Cascade did not calculate any costs for transporting gas to storage.
Fibre calculates this cost to be at least $172,339.07 per year.
If the costs referred to above are added, the full costs of the storage service
received by Cascade would be at least $1,273,324.90 per year:
OPTION A OPTION B
------------- -------------
Withdrawal Rate $588,912.00 $229,608.00
Adjustment
Carrying Cost of Gas 43,815.67 43,815.67
Transportation/Storage 23,066.44 23,066.44
Fuel Charges
Transportation In 172,339.07 172,339.07
Cascade's Storage Cost 804,495.76 804,495.76
Calculation
------------- -------------
Total $1,632,628.90 $1,273,324.90
DESPITE THE FOREGOING, WITHOUT PREJUDICE TO FIBRE'S POSITION IN ANY ARBITRATION
(AND OTHER POSSIBLE PROCEEDING) AND IN A GOOD FAITH EFFORT TO REACH SETTLEMENT
OF THIS MATTER, FIBRE MAKES THE FOLLOWING NON-SEVERABLE SETTLEMENT OFFER:
<PAGE>
- - the PGS fee would be reduced to $708,984.44 per year;
- - the reduced PGS fee would be applicable starting with the contract year
October 1996 to September 1997 and ending for the contract year October
2001 to September 2002;
- - amend the Peaking Gas Service Agreement to reflect the new five year firm
price with the option to renegotiate should gas and/or transportation rate
increase, affecting the agreement with Cascade's Washington Water Power
Storage Agreement; and
- - Cascade would provide Fibre with the following fuel management services for
the remaining term of the Agreement for PGS:
- an aggressive program, with daily consultations between
Cascade and Fibre, to release any part of the 48,000
dt/day of capacity on Northwest Pipeline for which Fibre
currently pays the reservation fees and which is not
needed by Fibre, with the proceeds from such releases
going to Fibre;
- an aggressive program, with daily consultations between
Cascade and Fibre, to resale any part of the 18,000
dt/day of natural gas (or additional supplies purchased
by Fibre) which Fibre currently buys from Duke or other
supplier and which is not needed by Fibre, with the
revenue from such resale going to Fibre;
- an aggressive program, with daily consultations between Cascade and
Fibre, to purchase gas at locations agreed to by Cascade and Fibre and
to have such gas delivered to Fibre;
- monthly reporting of the savings to Fibre under the above-stated
programs; and
- monthly balancing and reporting of all gas and transportation
activities related to Fibre.
If Cascade agrees with this settlement offer, please prepare and forward the
appropriate documents. If you have any questions regarding the above, do not
hesitate to contact me.
Sincerely,
<PAGE>
M. Smith, Jr.
Purchasing Manager
jr
cc: R. J. Parker
<PAGE>
AGREEMENT FOR PEAKING GAS SERVICE (PGS)
EXHIBIT B
OCTOBER 7, 1997
PGC FEE: CONTRACT YEAR: OCTOBER 1, 1996 THROUGH SEPTEMBER 30, 1997
PAYMENT SCHEDULE: OCTOBER, 1996 $ 80,862.50
November 80,862.50
December 80,862.50
January, 1997 80,862.50
February 80,862.50
March 80,862.50
April 80,862.50
MAY 80,862.50
June 0.00
July 0.00
August 0.00
September $ 80,862.50
------------
Total Paid Contract Year 1996-97 $ 727,762.50
Total Due Contract Year 1996-97 $ 708,894.44
------------
CREDIT $ 18,868.06
CONTRACT YEAR: OCTOBER 1, 1997 THROUGH SEPTEMBER 30, 1998
Payment Schedule: October, 1997
PREVIOUS YEAR'S CREDIT $18,868.06
Payment 40,206.48
-----------
$ 59,074.54
NOVEMBER 1, 1997 THROUGH SEPTEMBER 30, 1998 59,074.54 PER MONTH
Total Contract Year $708,894.44
Contract Year: October 1, 1998 through
September 30, 1999 per month $ 59,074.54
Total Contract Year $708,894.44
Contract Year: October 1, 1999 through
September 30, 2000 per month $ 59,074.54
Total Contract Year $708,894.44
Contract Year: October 1, 2000 through
September 30, 2001 per month $ 59,074.54
Total Contract Year $708,894.44
<PAGE>
EXHIBIT 12
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND PREFERRED DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
Twelve Months Ended
---------------------- -------------------------------------
9/30/97 9/30/96 12/31/95 12/31/94 12/31/93
------- ------- -------- -------- --------
(dollars in thousands)
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest expense $ 9,436 10,101 9,938 8,090 7,038
Amortization of debt
issuance expense 612 612 606 593 562
-------- -------- -------- -------- --------
Total fixed charges $10,048 10,713 10,544 8,683 7,600
-------- -------- -------- -------- --------
Earnings, as defined:
Net earnings $10,627 8,211 7,732 5,760 9,103
Add (deduct):
Income taxes 6,263 4,272 4,508 3,505 5,224
Cumulative effect of change
in accounting method - - - - (209)
Fixed charges 10,048 10,713 10,544 8,683 7,600
-------- -------- -------- -------- --------
Total earnings $26,938 23,196 22,784 17,948 21,718
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Ratio of earnings to
fixed charges 2.68 2.17 2.16 2.07 2.86
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Fixed charges and preferred
dividend requirements:
Fixed charges $10,048 10,713 10,544 8,683 7,600
Preferred dividend
requirements 811 819 853 898 913
-------- -------- -------- -------- --------
Total $10,859 11,532 11,397 9,581 8,513
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Ratio of earnings to fixed charges and
preferred dividend requirements 2.48 2.01 2.00 1.87 2.55
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
</TABLE>
<PAGE>
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
- --------------------------------------------------------------------------------
We consent to the incorporation by reference in Registration Statement No.
33-71286, No. 33-51377, No. 33-38501, and No. 33-29801 on Forms S-3, and No.
33-61035 and No. 33-39873 on Form S-8 of Cascade Natural Gas Corporation, of our
reports dated November 7, 1997, appearing in this Annual Report on Form 10-K of
Cascade Natural Gas Corporation for the year ended September 30, 1997.
DELOITTE & TOUCHE LLP
Seattle, Washington
December 29, 1997
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF CASCADE NATURAL GAS CORPORATION,
INCLUDED IN THE ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED
SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 265,225
<OTHER-PROPERTY-AND-INVEST> 2,161
<TOTAL-CURRENT-ASSETS> 28,831
<TOTAL-DEFERRED-CHARGES> 11,486
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 307,703
<COMMON> 10,967
<CAPITAL-SURPLUS-PAID-IN> 96,142
<RETAINED-EARNINGS> 4,553
<TOTAL-COMMON-STOCKHOLDERS-EQ> 111,662
6,630
0
<LONG-TERM-DEBT-NET> 121,150
<SHORT-TERM-NOTES> 7,500
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 5,400
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 55,361
<TOT-CAPITALIZATION-AND-LIAB> 307,703
<GROSS-OPERATING-REVENUE> 195,786
<INCOME-TAX-EXPENSE> 6,263
<OTHER-OPERATING-EXPENSES> 169,847
<TOTAL-OPERATING-EXPENSES> 169,847
<OPERATING-INCOME-LOSS> 25,939
<OTHER-INCOME-NET> 467
<INCOME-BEFORE-INTEREST-EXPEN> 20,143
<TOTAL-INTEREST-EXPENSE> 9,516
<NET-INCOME> 10,627
510
<EARNINGS-AVAILABLE-FOR-COMM> 10,117
<COMMON-STOCK-DIVIDENDS> 10,465
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 46
<EPS-PRIMARY> 0.93
<EPS-DILUTED> 0.93
</TABLE>
