<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, 1999 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 (206) 624-3900
Seattle, WA 98109 --------------
------------------ (Registrant's telephone number
(Address of principal executive offices) 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. X
---
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 December
14, 1999, was $182,179,824
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 11,045,095 as of December 14, 1999
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for its 2000
Annual Meeting of Shareholders are incorporated by reference into Part III,
Items 10, 11, 12, and 13.
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CASCADE NATURAL GAS CORPORATION
ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION ON FORM 10-K
For the Fiscal Year Ended September 30, 1999
Table of Contents
<TABLE>
<CAPTION>
Number Page
- ------ ----
<S> <C>
Part I
Item 1 - Business 3
Item 2 - Properties 7
Item 3 - Legal Proceedings 8
Item 4 - Submission of Matters to a Vote of Security Holders 8
Executive Officers of the Registrant 8
Part II
Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters 9
Item 6 - Selected Financial Data 10
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations 12
Item 7a- Quantitative and Qualitative Disclosures about Market Risk 18
Item 8 - Financial Statements and Supplementary Data 20
Item 9 - Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 41
Part III
Item 10 - Directors and Executive Officers of the Registrant 41
Item 11 - Executive Compensation 41
Item 12 - Security Ownership of Certain Beneficial Owners
and Management 41
Item 13 - Certain Relationships and Related Transactions 41
Part IV
Item 14 - Exhibits, Financial Statement Schedules and
Reports on Form 8-K 42
Signatures 43
Index to Exhibits 44
</TABLE>
2
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PART I
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 81% of its gas distribution revenues are
from customers in the state of Washington.
As of September 30, 1999, the Company had approximately 177,162 core
customers and 189 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 18% of gas deliveries and 70% 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.
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.
Effective December 1998, with respect to such gas supplies delivered to Oregon
customers, 67% of the incremental change in the actual cost of gas supplies, as
compared to the forecasted cost reflected in the PGA, is deferred. The remaining
33% (increase or decrease) is absorbed by the Company. This mechanism is
intended to encourage the Company to seek opportunities to lower its cost of
supplies and to be innovative in its management of the supply portfolio to avoid
price spikes.
Cascade has an earnings sharing mechanism with respect to its Oregon
jurisdictional operations. See "Regulatory Matters" under Item 7 for a
description of the mechanism.
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 1999 with both the WUTC and the OPUC. The IRP
shows the Company's optimum set of supply and demand side resources that
minimizes costs and risk over the twenty-year planning horizon. The IRP also
sets forth possible core customer growth scenarios 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 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
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strategic decisions. Until the Company receives final regulatory approval of
these decisions in the context of the rate making process, 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). 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 a shipper on the Pacific Gas and Electric Gas
Transmission Northwest (PG&E GT NW) system. PG&E GT NW 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. Cascade also
receives natural gas directly from Westcoast Energy, Inc. at the Canadian border
near Sumas, Washington.
Presently, baseload requirements for Cascade's core market group are
provided by six major gas supply contracts with various expiration dates from
2000 through 2008 and totaling 764,830 therms per day. Approximately 90% 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. One with
Williams 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 Avista 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, also with Williams, 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 a
contract with a major industrial customer whereby the customer agrees to switch
to alternate fuel allowing Cascade to reduce firm deliveries to that customer.
Cascade then takes the customer's firm gas supply and pipeline capacity to serve
its core markets. In return, Cascade reimburses the customer for the cost of its
alternate fuel and pipeline capacity. Since the customer is also a distribution
customer of Cascade, the supply is already being delivered to Cascade's system
and is merely diverted to core customers, allowing for an even greater
accommodation of late day demand spikes. Because the customer'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. This peak shaving
agreement, which expires in 2014, entitles Cascade to call on 150,000 therms per
day up to a seasonal total of 3,000,000 therms.
During 1999, Cascade purchased approximately 90% of its gas supplies
from firm gas supply contracts and 10% from 30-day spot market contracts. In
addition, 912 million therms of customer purchased supplies were transported
through Cascade facilities.
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 is purchased primarily on fixed price
contracts. Management believes that this, 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.
OREGON GAS COST ADJUSTMENTS
Prior to December 1998, in Oregon Cascade was subject to an 80/20%
sharing mechanism for changes in the commodity cost of gas supplies. If actual
commodity gas prices were higher or lower than
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predicted in the PGA filing, 80% of the incremental change was passed through
to core customers in rates while Cascade kept or absorbed the remaining 20%.
Coupled with the 80/20 sharing was an Earnings Review Test. Cascade's ability
to adjust rates to recover higher than predicted gas costs was limited to the
extent that adjusted operating results during the relevant period exceeded
rate of return ceilings calculated by the staff of the OPUC. For purposes of
the test, adjustments, such as one to impute normal rather than actual
weather, were made to operating results. As a consequence, limitations on gas
cost recovery could be imposed even when actual earnings were lower than the
OPUC staff's ceiling. Effective December 1, 1998, the Company and OPUC staff
agreed to drop the Earnings Review Test and modify the sharing mechanism for
commodity gas cost changes to a 67/33% split.
Cascade's current gas supply portfolio for Oregon core customers is
comprised mostly of gas supplies that have a fixed commodity price, therefore
management believes that there will be little risk or opportunity for the
Company under the 67/33% sharing arrangement during the coming year. For the
period beginning December 1998 through September 1999, under the new
arrangement, Cascade's 33% share of savings achieved totaled $116,000.
FEDERAL ENERGY REGULATORY COMMISSION (FERC) MATTERS
Cascade is not subject to regulation by the FERC, however FERC actions
can affect the amounts Cascade pays to interstate pipeline companies for
interstate deliveries of natural gas supplies. Several issues are pending before
FERC, or are on appeal before the U.S. Court of Appeals. The final outcome may
affect prices Cascade pays. Since the policies of the WUTC and OPUC provide for
100% pass through of costs subject to FERC regulation, the Company expects that
the final resolution of pending issues will not affect net earnings.
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 conditions. 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 will not be liable for damages 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
charges to firm customers curtailed by reason of an insufficient supply of gas.
TERRITORY SERVED AND FRANCHISES
The population of communities served by Cascade totals approximately
780,000. 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 2000 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.
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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 at least 30-days' notice.
The principal industrial activities in Cascade's service area include
the production of pulp, paper and converted paper products, plywood, chemical
fertilizers, industrial chemicals, clay and ceramic products, refining of crude
oil, producing and forming of aluminum, the processing, flash freezing 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, and electric power generation. Electric generation customers represent
a significant portion of industrial revenues. The demand for gas fired
generation tends to decrease as the availability of hydroelectric generation
increases.
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, 1999, 64% of operating revenues and 89% of earnings from
operations were derived from the first two quarters (October 1998 through March
1999). Because of the seasonality of space heating revenues, Cascade believes
financial results for interim periods are not indicative of results to be
expected for an entire year. To mitigate the seasonality of space heating
revenues, the Company pursues a marketing strategy of encouraging the
installation of gas water heaters by customers, since they are not as influenced
by weather conditions.
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, propane, 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. In addition, natural gas enjoys the
advantage of being the preferred energy choice by builders for new home
construction.
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 have improved the Company's
competitive position. Cascade has not experienced any significant loss of sales
to alternate fuels to these customers during the last ten years, even though
there have been periods when the residual fuel oil prices were lower than
natural gas.
In addition to multiple alternative fuels, the Company is subject to
bypass. Bypass refers to actual or prospective customers who 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. In addition, other sellers of natural gas compete to sell the natural
gas commodity over the Company's pipelines to its distribution customers.
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.
For detailed descriptions of specific environmental issues, see "Environmental
Matters" under Item 7.
CAPITAL EXPENDITURES
Capital expenditures are primarily used 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. Capital expenditures for the five years ended September 30, 1999
totaled approximately $134.7 million, and the budget for fiscal 2000 is $23.5
million. Fiscal 1999 capital expenditures were $17.2 million, $6.6 million less
than the prior year, due to improved cost controls, higher contributions by
customers, the rescheduling of certain projects, and lower technology
expenditures.
The Company is currently forecasting that capital expenditures will
total approximately $124 million over the next five years, reflecting
expectations that customer growth will continue at a pace similar to recent
experience but that spending on system reinforcement will be lower. Management
performs quantitative and qualitative analyses to assure that the Company's
goals and strategies are met. The overall objective is to invest limited capital
to generate the highest possible returns within the shortest possible time,
while assuming prudent risk, anticipating customer needs and complying with the
requirements of regulators.
NON-UTILITY SUBSIDIARIES
Cascade has four non-utility subsidiaries, only two of which are
actively engaged in business at present. Cascade Land Leasing is engaged in the
servicing of loans that were made to Cascade's gas customers to finance their
purchases of energy-efficient appliances. The subsidiary ceased making new loans
in September 1997. Beginning in November 1998, CGC Resources began serving as an
entity engaged in pipeline capacity management, with the objective of mitigating
gas costs for Cascade. 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, 1999, Cascade had 451 employees. Of the total
employees, 207 are represented by the International Chemical Workers Union. The
present contract with the union extends to April 1, 2001, and thereafter until
terminated by either party on sixty days' notice. As of September 30, 1998,
three Company executives including the president accepted an early retirement
offer. The Company does not intend to replace these positions, but has instead
restructured management to cover the vacated areas of responsibilities.
ITEM 2. PROPERTIES
At September 30, 1999, Cascade's utility plant investments included
approximately 4,412 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 2,846 miles of service lines.
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 buildings used for operations, office
space and warehousing in Washington and seven such buildings in Oregon. It
leases an additional seven commercial offices and
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warehouse buildings. 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
The information under "Environmental Matters" in Item 7 is incorporated
herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
EXECUTIVE OFFICERS OF THE REGISTRANT
The executive officers of the Company, as of December 1, 1999, are as follows:
<TABLE>
<CAPTION>
Year
Became
Name Office Age Officer
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
W. Brian Matsuyama Chairman of the Board,
President and
Chief Executive Officer 53 1987
Jon T. Stoltz Senior Vice President -
Planning, Regulatory
& Consumer Affairs 52 1981
J. D. Wessling Senior Vice President - Finance
and Chief Financial Officer 56 1995
Larry E. Anderson Vice President -
Operations 51 1995
King C. Oberg Vice President -
Gas Supply 58 1993
James E. Haug Controller and Chief
Accounting Officer 50 1981
Larry C. Rosok Vice President - Human Resources
and Corporate Secretary 43 1995
</TABLE>
None of the above officers is related by blood, marriage or adoption to
any other of the above named officers. 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.
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PART II
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.
<TABLE>
<CAPTION>
Fiscal 1999 Fiscal 1998
----------- -----------
Quarter High Low High Low
------- ---- --- ---- ---
<S> <C> <C> <C> <C>
December 31 $18-9/16 $16-1/8 $19 $16-1/2
March 31 18-1/8 14-15/16 18-9/16 15-1/2
June 30 19 14-5/8 17-3/16 15-5/16
September 30 18-11/16 16-9/16 16-1/2 14-5/8
</TABLE>
At November 24, 1999, there were approximately 7,407 holders of the
Common Stock. The following table shows for the periods indicated the dividends
paid per share on the Common Stock.
<TABLE>
<CAPTION>
Quarter 1999 1998
------- ---- ----
<S> <C> <C>
December 31 $ 0.24 $ 0.24
March 31 $ 0.24 $ 0.24
June 30 $ 0.24 $ 0.24
September 30 $ 0.24 $ 0.24
</TABLE>
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ITEM 6. SELECTED FINANCIAL DATA
(dollars in thousands except per share data)
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended Nine Months Year Ended
Sep 30 Sep 30 Sep 30 Ended Sep 30 Dec 31
1999 1998 1997 1996 1995
------------- ------------- ------------- ------------- -----------
<S> <C> <C> <C> <C> <C>
STATEMENTS OF OPERATIONS:
Operating Revenues $208,610 $189,656 $195,786 $127,665 $182,744
Less: Gas Purchases 109,263 97,382 104,342 69,679 102,858
Revenue Taxes 13,280 12,037 12,430 8,420 11,480
------------- ------------- ------------- ------------- -----------
Operating Margin 86,067 80,237 79,014 49,566 68,406
------------- ------------- ------------- ------------- -----------
Cost of Operations:
Operating expenses 36,313 37,310 35,670 25,058 30,818
Depreciation and amortization 12,841 13,470 13,416 9,362 11,733
Property and payroll taxes 4,574 4,420 3,989 3,181 4,051
------------- ------------- ------------- ------------- -----------
53,728 55,200 53,075 37,601 46,602
------------- ------------- ------------- ------------- -----------
Earnings From Operations 32,339 25,037 25,939 11,965 21,804
------------- ------------- ------------- ------------- -----------
Nonoperating Expense (Income):
Interest 10,486 10,132 9,436 7,459 9,938
Interest charged to construction (383) (550) (532) (569) (394)
------------- ------------- ------------- ------------- -----------
10,103 9,582 8,904 6,890 9,544
Amortization of debt issuance expense 603 605 612 459 606
Other (495) (388) (467) (2) (586)
------------- ------------- ------------- ------------- -----------
10,211 9,799 9,049 7,347 9,564
------------- ------------- ------------- ------------- -----------
Earnings Before Income Taxes 22,128 15,238 16,890 4,618 12,240
Income Taxes 8,075 5,694 6,263 1,606 4,508
------------- ------------- ------------- ------------- -----------
Net Earnings 14,053 9,544 10,627 3,012 7,732
Preferred Dividends 483 497 510 393 539
------------- ------------- ------------- ------------- -----------
Net Earnings Available to
Common Shareholders $ 13,570 $ 9,047 $ 10,117 $ 2,619 $ 7,193
============= ============= ============= ============= ===========
Net Earnings per Common Share
(Basic and diluted) $ 1.23 $ 0.82 $ 0.93 $ 0.28 $ 0.80
</TABLE>
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ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
(dollars in thousands except per share data)
<TABLE>
<CAPTION>
At September 30 At Dec 31
--------------------------------------------------- ---------
1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
RETAINED EARNINGS:
Beginning of the year $ 3,003 $ 4,553 $ 4,901 $ 9,297 $ 10,806
Net earnings available to
common shareholders 13,570 9,047 10,117 2,619 7,193
Common dividends (10,603) (10,597) (10,465) (7,015) (8,702)
----------------------- ----------------------- ---------
End of the year $ 5,970 $ 3,003 $ 4,553 $ 4,901 $ 9,297
----------------------- ----------------------- ---------
CAPITAL STRUCTURE:
Common shareholders' equity $ 114,395 $ 111,428 $ 111,662 $ 109,126 $ 89,539
Redeemable preferred stocks 6,186 6,408 6,630 6,851 6,851
----------------------- ----------------------- ---------
Debt:
Long-term debt 125,000 110,650 121,150 101,850 102,100
Notes Payable and Commercial Paper -- 6,929 12,900 -- 32,000
Current maturities of long-term debt -- 10,000 -- -- --
----------------------- ----------------------- ---------
125,000 127,579 134,050 101,850 134,100
----------------------- ----------------------- ---------
Total capital $ 245,581 $ 245,415 $ 252,342 $ 217,827 $ 230,490
======================= ======================= =========
FINANCIAL RATIOS:
Return on common shareholders' equity 11.52% 7.77% 8.75% 8.09% 8.12%
Common stock dividend payout ratio 78% 117% 103% 257% 120%
Cash dividends declared per common share $ 0.96 $ 0.96 $ 0.96 $ 0.72 $ 0.96
Fixed charge coverage (before income
tax deduction):
Times interest earned 3.00 2.42 2.68 2.17 2.16
Times interest and preferred
dividends earned 2.80 2.26 2.48 2.01 2.00
Book value per year-end share
of common stock $ 10.33 $ 10.09 $ 10.18 $ 10.12 $ 9.79
Capitalization Ratios at End of Year
Common shareholders' equity 46.6% 45.4% 44.3% 50.1% 39.6%
Preferred stock 2.5% 2.6% 2.6% 3.1% 3.3%
Long-term debt (incl. current) 50.9% 49.2% 48.0% 46.8% 48.4%
Short-term debt 0.0% 2.8% 5.1% 0.0% 8.7%
----------------------- ----------------------- ---------
100.0% 100.0% 100.0% 100.0% 100.0%
----------------------- ----------------------- ---------
UTILITY PLANT:
Utility plant - end of year $ 453,278 $ 433,568 $ 416,365 $ 383,771 $ 362,924
Accumulated depreciation 177,878 167,356 160,332 147,599 138,831
----------------------- ----------------------- ---------
Net plant $ 275,400 $ 266,212 $ 256,033 $ 236,172 $ 224,093
======================= ======================= =========
Capital expenditures, net
of contributions in aid $ 17,262 $ 23,780 $ 21,626 $ 26,053 $ 37,637
======================= ======================= =========
Total assets $ 315,569 $ 311,511 $ 307,703 $ 296,381 $ 296,898
======================= ======================= =========
</TABLE>
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 and cash flows for the fiscal years ended September 30,
1999, 1998, and 1997.
EARNINGS PER SHARE
Net earnings available to common shareholders were $13,570,000, or
$1.23 per common share for fiscal 1999, representing a 50% improvement over the
$9,047,000, or $0.82 per common share, reported for fiscal 1998. The improvement
in earnings is primarily the result of higher operating margins. Reductions in
operating expenses and depreciation also contributed to the improvement.
OPERATING MARGIN
RESIDENTIAL AND COMMERCIAL MARGIN for the fiscal years ended September
30, 1999, 1998, and 1997 are set forth in the table below:
Residential and Commercial Operating Margins
(dollars in thousands)
<TABLE>
<CAPTION>
(12 months ended September 30)
1999 1998 1997
- -----------------------------------------------------------------
<S> <C> <C> <C>
Degree Days 5,535 5,031 5,525
Average Number of Customers
Residential 150,068 142,537 134,857
Commercial 26,360 25,409 24,682
Average Therm Usage Per Customer
Residential 799 747 817
Commercial 4,058 3,931 4,348
Operating Margin
Residential $ 35,072 $ 30,436 $ 29,725
Commercial $ 21,886 $ 19,648 $ 20,523
</TABLE>
Fiscal 1999 operating margins from sales to residential and commercial
customers were up $6,874,000, or 13.7%, compared to fiscal 1998. The primary
factors contributing to this improvement were increased per-customer gas usage,
increased number of customers, and a $1 per month increase in the monthly
service charge paid by Washington customers.
Approximately $2.8 million of the increase is attributable to increased
consumption per customer, largely due to colder weather. Weather in fiscal 1999,
as measured by heating degree-days, while approximately 2% warmer than normal,
was 10% colder than fiscal 1998. Improvement of approximately $2.4 million was
the result of the 5% increase in the number of customers.
A $1 per month service charge increase added approximately $1.3 million
in margin. The increase was offset by a corresponding decrease in the rates
charged to industrial customers. This shift in rate responsibility was approved
by the Washington Utilities & Transportation Commission (WUTC) effective August
1, 1996. The approval provided for a phased in shift of rate responsibility in
three annual increments, on August 1, 1996, 1997, and 1998. The intended result
was to produce no direct bottom line impact.
12
<PAGE>
1998 VERSUS 1997. Fiscal 1998 operating margins from sales to
residential and commercial customers were down $164,000, or 0.3% compared to
fiscal 1997. Several factors contributed to this decrease but most significant
was the decline in gas consumption resulting from warm weather during the 1997 -
1998 winter heating season. Weather in fiscal 1998, as measured by heating
degree days, was approximately 11% warmer than normal, and 9% warmer than the
prior year. The lower gas consumption depressed margins by an estimated $4
million, or $0.23 per share, compared to 1997. Also reducing margins by
approximately $700,000 was a September 1, 1997 reduction in rates which passed
on to Oregon customers a part of the benefit of efficiencies and lower capital
costs since Cascade's last general rate case in that state.
Other factors substantially mitigated these decreases. The 5.3% growth
in the number of customers contributed approximately $2.4 million of margin.
Monthly service charges collected from customers in Washington increased $1.00
on August 1, 1997, and again on August 1, 1998. These service charge increases
contributed approximately $1.4 million of margin. Offsetting the higher service
charges was a reduction in rates charged to industrial and other customers, as
was described above. Also affecting the comparison were more stable wholesale
prices of natural gas in fiscal 1998. During the fiscal 1997 heating season, gas
supply prices spiked to abnormally high levels. Regulatory provisions in Oregon
require that the Company absorb a portion of such price variances. During fiscal
1998, more stable prices prevailed, and the Company was able to earn a small
profit from favorable prices. The resulting difference was an approximate
$900,000 margin improvement.
INDUSTRIAL AND OTHER MARGIN in fiscal 1999 decreased $840,000, or 2.8%
from fiscal 1998. Approximately $1.3 million represents the rate reduction
offset for the increased residential and commercial service charges. Also in
1999, margins from the sales of spot market gas declined $519,000. Partially
offsetting these decreases is approximately $800,000 in margins from 70, mostly
smaller, new industrial customers and $700,000 from consumption increases by
existing industrial customers.
1998 VERSUS 1997. Margins from industrial and other customers in fiscal
1998 increased $1.4 million or 4.8% over fiscal 1997. This improvement was
primarily due to greater deliveries to the Company's electric generation
customers. The higher demand for gas-fired generation was driven in part by the
diminished availability of hydroelectric generation, resulting from the previous
winter's low snowfall in the northwest. The addition of several smaller
industrial customers also contributed to the improvement in operating margins.
Partially offsetting the margin improvements from industrial customers
for both 1997 and 1998 were rate reductions equivalent to the amount derived
from the higher monthly service charges to residential and commercial customers
(see "Residential and Commercial Margin").
COST OF OPERATIONS
Cost of operations, which consists of operating expenses, depreciation
and amortization, and property and payroll taxes, was $53.7 million, $55.2
million, and $53.1 million for the fiscal years ended September 30, 1999, 1998,
and 1997, respectively.
OPERATING EXPENSES for fiscal 1999, which are primarily labor and
benefits expenses, decreased $997,000, or 2.7% from 1998. Improved efficiencies
have resulted in the reduction of 22 personnel positions since the end of 1998.
The average employee count in 1999 was 468 compared to 483 in 1998, and these
reductions were achieved through normal attrition and early retirements. As a
result of these staffing reductions, savings in labor expense of $946,000 were
realized in 1999 compared to 1998. In addition, overtime pay decreased $137,000.
These reductions were offset by $1.3 million of normal wage and salary rate
increases, and incentive compensation accruals for all salaried employees.
Additional reductions were achieved in other expense categories,
including administrative, advertising, and operations.
13
<PAGE>
For fiscal 1998, operating expenses increased by $1.7 million, or 4.7%,
over fiscal 1997. Labor expense was higher by $560,000, or 2.4%. Lower credits
for labor and other expenses charged to construction resulted in higher
operating expense of $504,000. Also included in operating expenses was a
one-time charge of $369,000, recorded in the fourth quarter, for the cost of an
early retirement opportunity that was accepted by three of the Company's
executives, who retired as of September 30, 1998.
DEPRECIATION AND AMORTIZATION for fiscal 1999 decreased $629,000, or
4.7% from 1998. Based on results of a depreciation study, conducted during 1998,
the Company implemented lower depreciation rates effective with the fourth
quarter of fiscal 1998. The annual effect of the lower rates is an approximate
$2 million reduction in depreciation expense. The effect on the comparison of
fiscal 1999 to 1998 is approximately $1.5 million. Incremental depreciation
expense on new assets placed in service was approximately $900,000.
For fiscal 1998, depreciation and amortization increased by $54,000 or
0.4% over fiscal 1997. Lower depreciation rates as of July 1, 1998 resulted in
decreased expense by approximately $500,000, offsetting the effect of additions
to depreciable utility plant.
PROPERTY AND PAYROLL TAXES for fiscal 1999 were higher by $154,000, or
3.5% compared to fiscal 1998. Of the increase, $111,000 is related to the timing
of recognition of property tax reductions in Oregon. Beginning in 1991, and
resulting from a voter mandate in 1990 (Ballot Measure 5), Oregon property tax
rates decreased each year for a five year period. For each of those five years,
the Oregon Public Utility Commission required regulated energy utilities to
measure and defer in a regulatory liability account, the effect of the resulting
property tax reductions. Each year from 1994 to 1997, the Company reduced its
customer rates to reflect the lower tax expense incurred, and to refund the
deferred amounts to its customers. The amount refunded to customers varied each
year and was set by the OPUC. Concurrent with the rate reductions, the Company
recorded credits to property tax expense, which amortized the deferrals in
amounts equivalent to the reduced revenue. Accordingly, there was no net effect
on earnings. The amortization was completed in the first quarter of fiscal 1998.
Property and payroll taxes in fiscal 1998 were higher by $430,000, or
10.8%, compared to fiscal 1997. The increase is primarily related to the timing
of recognition of property tax reductions in Oregon as discussed in the
preceding paragraph.
NONOPERATING EXPENSE (INCOME)
Interest expense for 1999 increased by $354,000 or 3.5% from fiscal
1998. The increase was due primarily to higher long-term debt, higher average
short-term debt and deferred gas cost balances. Interest charged to construction
decreased $167,000 because of lower construction expenditures and lower balances
in construction work in progress. Other income increased $107,000, mainly
because of a gain of $174,000 on the sale of non-utility property, partially
offset by reductions in interest and other income of $67,000.
Interest expense for 1998 increased by $696,000 or 7.4% from fiscal
1997. The increase was due primarily to additional amounts of outstanding
long-term debt, partially offset by lower short-term debt and lower interest
accrued on deferred gas cost balances. The comparison of other non-operating
income was affected by the inclusion in 1997 of a $140,000 gain on the sale of a
parcel of land. Additionally, there was less interest income in fiscal 1998
because of lower outstanding appliance loan amounts.
INCOME TAXES
The increase in the provision for federal and state income taxes is
attributable to improvements in pre-tax earnings. The average effective income
tax rate for 1999 is 36.5%, compared to 37.4% for 1998 and 37.1% for 1997.
Increases in pretax income mitigate the effective rate impact of the differences
between the statutory and effective tax rates.
14
<PAGE>
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 credit commitment of $40 million from three banks. This agreement expires in
September 2000; however, the Company is currently finalizing terms for a new
5-year agreement. The Company uses the facility to meet short-term needs as well
as to support a money market facility and a commercial paper facility of a
similar amount. The annual commitment fee is 1/8 of one percent. The Company
also has $30 million of uncommitted lines from three banks.
A Medium-Term Note program provides longer term financing with $125
million outstanding at September 30, 1999. There is $15 million remaining
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
Cash from operating activities, less cash dividends paid, provided 100%
of capital expenditures in fiscal 1999. Although net earnings for fiscal 1999
were higher by $4,509,000 than for 1998, net cash provided by operating
activities was $28,178,000, compared to $38,564,000 last year. Affecting the
comparison was the difference in cash flows from changes in current assets and
liabilities. This change is primarily the result of timing differences related
to changes in accounts receivable, accounts payable, and accrued taxes.
INVESTING ACTIVITIES
Cash used by investing activities in fiscal 1999 was $16.1 million,
compared to $22.9 million in 1998. Capital expenditures in fiscal 1999 were
lower due to several factors, including delays until the first quarter of fiscal
2000 in the completion of facilities to serve a major new customer and lower
expenditures on distribution system reinforcement projects. Also, new
feasibility rules applicable to the Company's Washington operations have had the
desired effect of discouraging marginally feasible new customer hookups or
requiring marginal customers to contribute more toward the cost of new plant.
Under the new rules, customers are required to contractually commit to install
appliances that will utilize enough gas to make the Company's investment in
plant profitable.
Budgeted capital expenditures for fiscal 2000 are approximately $23.5
million, which is expected to be financed approximately 75% from operating
activities, and 25% from debt financing.
FINANCING ACTIVITIES
Cash used for financing activities was $14.0 million in fiscal 1999,
and $16.5 million in 1998. Other than the payment of dividends, the principal
financing activities in 1999 involved replacement of debt. During the first
quarter the Company redeemed $10 million of medium-term notes, which matured in
December. This redemption was funded with short-term debt. In March, the Company
issued $15 million of new 7.098% medium-term notes with a 30-year maturity.
Proceeds were used primarily to pay down short-term debt. At September 30, 1999,
the Company had no short-term debt.
In the first quarter of fiscal 2000, the Company redeemed the $6
million, 7.85% cumulative preferred stock. This redemption was funded with
short-term debt.
15
<PAGE>
REGULATORY MATTERS
In the first quarter of fiscal 1999, the OPUC approved the agreement
that had been reached between the Company and the OPUC Staff regarding an
Earnings Sharing Mechanism. Under that mechanism, first effective for calendar
year 1999, Cascade shares with its Oregon customers one third of earnings that
exceed a return on equity (ROE) ceiling. The ROE ceiling will be adjusted over
time based upon the change in the average US Treasury 5, 7, and 10-year bond
rates. Based upon current bond rates, the ROE ceiling before any sharing occurs
is 12.60%. The estimated effect of this sharing arrangement for the first nine
months of calendar 1999 is $204,000. The approved agreement also dropped
previous limitations that allowed recovery of certain gas cost increases only if
earnings, adjusted for normal weather, were below set return levels. Management
believes the new mechanisms are favorable, in that they should reduce the risk
of losing the benefit of efficiency gains and the risk of being unable to
recover actual costs of gas.
ENVIRONMENTAL MATTERS
In 1995, the Company received a claim from a property owner in Eugene,
Oregon requesting that the Company assume responsibility for investigation and
possible clean up of alleged contamination on property previously owned by a
predecessor of Cascade. The predecessor company conducted a manufactured gas
business on the property from approximately 1929 to 1948. Manufactured gas
operations apparently were conducted on the site by several operators beginning
about 1907. The site was used for other purposes beginning in 1949.
The present owner has retained an environmental consultant, which is
investigating possible contamination on the property. To date the consultant has
reported that it believes contamination is present. The contamination is
consistent with that which might originate from a manufactured gas operation.
There have been no estimates as to possible clean up costs. The consultant's
initial report has been furnished to the Oregon Department of Environmental
Quality (DEQ). The owner has reached an intergovernmental agreement with the DEQ
with respect to further investigation and possible remediation of contamination
on the property under the voluntary cleanup program.
Another northwest utility, which purchased the property from Cascade in
1958, has declined to participate in the site investigation, although it may, as
a onetime owner of the property, bear some share of the responsibility as well.
The Company has notified its insurance carriers of the claim and is
keeping them advised as to the investigation. On one occasion in the past when
hazardous materials on property formerly owned by a predecessor of the Company
required clean up, the OPUC allowed the clean up costs to be passed on to
customers. In the event the Company is responsible for clean up costs not
covered by insurance, management anticipates asking for reimbursement through
rates for such costs.
In 1997, a property owner in Washington notified the Company that there
is contamination on his property, and that he believes it comes from a former
manufactured gas site, owned at one time by a predecessor company, which was
merged with Cascade in 1953. The State of Washington Department of Ecology has
categorized this site as a "listed site" ranked in its most hazardous category.
As a former owner of the site, the Company may be strictly liable to the State
of Washington for investigation and remediation of the contamination of the
site, but may share that cost or allocate all the cost to others who actually
caused or contributed to the contamination.
The Company retained an environmental consultant who conducted a
preliminary investigation of possible contamination at the site. There is
evidence of contamination at the site, and there is also evidence of an oil line
across the site property owned and operated by others, which may be a
contributor to the contamination. There have been no estimates as to possible
clean up costs. The Company has investigated title and other government records
to identify other potentially liable parties. The Company has notified the other
identified parties of the contamination claims, and has requested cooperation
and financial contribution.
16
<PAGE>
In the event the Company is responsible for clean up costs not covered
by insurance, management anticipates asking the WUTC for reimbursement for such
costs, through rates charged to customers.
YEAR 2000 READINESS DISCLOSURE
This Year 2000 Readiness Disclosure is based in part on information
provided to the Company by outside suppliers and vendors. While the Company
believes this outside information is accurate, Cascade is not the source of this
information and has not independently verified the information submitted by
third parties.
Cascade is heavily reliant on computers for internal and external
information processing. The Year 2000 issue is the result of computer systems
and other equipment with embedded processors that use two digits rather than
four to define a year date. Problems can occur when computer applications fail
to distinguish between the year 1900 and 2000. To mitigate potential problems
associated with this issue, Cascade began in 1996 to address the compliance of
those computers and systems that are critical to business operations. In
addressing this issue, the Company employed a five-phase process: 1) organize
and inventory all peripherals, applications, software, metering equipment,
communications equipment and date-related logic systems that could be impacted;
2) assess those systems that require modification or replacement; 3) upgrade or
replace non-compliant equipment and systems; 4) test and validate all mission
critical systems and implement test data migration plans and procedures for
large applications; and 5) place compliant systems and equipment into service.
The Company has also engaged in a process to assess upstream suppliers
including pipeline companies, vendors and other utilities of their compliance
status. To date, the Company has received communications from substantially all
significant suppliers and vendors. While no company can provide assurance that
suppliers will be compliant, Cascade has not received indication that any major
third party will have a compliance problem adversely affecting its ability to
conduct business. Cascade believes those statements it has received are
accurate, however the company is not the source of this information and has not
independently verified the information. The Company continues to monitor the
compliance process of external systems, suppliers and vendors.
RISKS
Despite efforts to address all significant Year 2000 issues in advance,
the company could potentially experience disruptions to some aspects of its
activities or operations, including, but not limited to, delays in payments to
the company from customers. Currently, Cascade has not received any indication
that customers, third party suppliers or vendors will experience problems that
could impact Cascade. However, there can be no guarantee that the systems of
other companies with whom the Company transacts business will be timely
converted.
In the unlikely event that internal computer systems fail due to a year
2000 compliance problem, business processes that may be interrupted include:
automated monitoring of gas flow and pressure; measurement of gas receipts from
suppliers and deliveries to customers; processing customer invoices; payments to
suppliers; financial measurement and reporting; internal and external
communications; payroll processing; and other administrative functions.
Management has not developed estimates of losses that may be incurred in the
event of a failure of one or more of these systems.
STATE OF READINESS
Management believes that all mission critical systems have been
identified. The Company has upgraded or replaced most of its third-party
financial and distribution system monitoring hardware and software and has
established that these systems are now Year 2000 compliant. All of the Company's
personal computers, embedded building and office systems, and fleet vehicles
have also been assessed, tested, and verified to be compliant. Corrections to
internally developed software, including billing, cash receipts processing, and
payroll are complete and have tested to be compliant. The company's new SCADA
system, which monitors natural gas pressure and volume on the Company's
distribution system, was fully tested and placed into service in December 1999.
17
<PAGE>
COSTS OF YEAR 2000 COMPLIANCE
The Company has used a combination of internal and external resources
to make necessary modifications to existing systems. The Company does not
separately track the direct costs associated with such internal personnel, which
primarily consist of salary and benefits. Costs associated with using internal
resources is viewed primarily as an opportunity cost, resulting in a delay of
other planned system enhancements and replacements intended to enhance operating
efficiencies. Such delays are not expected to have a material adverse effect on
the Company or its competitive position.
Fiscal Year 1999, capital expenditures to replace non-compliant vendor
based systems total approximately $769,000. Project-to-date expenditures total
approximately $1.3 million. Estimated total capital expenditures are expected to
be $1.9 million. Though Year 2000 compliance is the primary motivating factor
for these system replacements, management anticipates other significant
improvements from these systems as compared to the old systems.
Although the costs and completion dates discussed above are based on
management's best estimates, actual results may differ from expectations.
CONTINGENCY PLANNING
The Company has given consideration to several worst-case Year 2000
scenarios and has developed a YEAR 2000 BUSINESS CONTINUITY AND DISTRIBUTION
SYSTEM MONITORING PLAN that outlines manual monitoring and operating procedures
of critical facilities. The Company's Plan will be enacted in the event there
are short-term failures to purchased power, gas supplies, telecommunications,
and internal computer systems. The plan addresses key operating processes and
the roles of individuals in the event of such failures.
Management believes the most likely worst case scenario is that
necessary program code modifications of legacy computer systems may have been
overlooked. The response to such an event is the dedication of available
programming staff to correct the problem. The Company reviews and updates its
remediation schedule and contingency plan as needed.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Cascade has evaluated its risk related to financial instruments whose
values are subject to market sensitivity. The only such instruments are Company
issued fixed-rate debt obligations. Cascade makes interest and principal
payments on these obligations in the normal course of its business, and does not
plan to redeem these obligations prior to normal maturities. Accordingly,
management believes the Company is not subject to market risk as defined in Item
305 of Regulation S-K.
18
<PAGE>
FORWARD-LOOKING STATEMENTS
Statements contained in this report that 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, misjudgments
in assessing the Company's year 2000 compliance requirements and risks,
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.
19
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
Board of Directors
Cascade Natural Gas Corporation
Seattle, Washington
We have audited the consolidated balance sheets of Cascade Natural Gas
Corporation and subsidiaries (the Corporation) as of September 30, 1999 and
1998, and the related consolidated statements of net earnings available to
common shareholders, common shareholders' equity, and cash flows for the years
ended September 30, 1999, 1998 and 1997. These financial statements are the
responsibility of the Company'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, 1999 and 1998, and the results of its
operations and its cash flows for the years ended September 30, 1999, 1998 and
1997, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Seattle, Washington
November 5, 1999
20
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF NET EARNINGS AVAILABLE TO COMMON SHAREHOLDERS
(Dollars in thousands except per share data)
<TABLE>
<CAPTION>
Year Ended September 30,
-------------------------------------------------
1999 1998 1997
------------- -------------- --------------
<S> <C> <C> <C>
Operating Revenues $ 208,610 $ 189,656 $ 195,786
Less
Gas purchases 109,263 97,382 104,342
Revenue taxes 13,280 12,037 12,430
------------- -------------- --------------
Operating Margin 86,067 80,237 79,014
------------- -------------- --------------
Cost of Operations
Operating expenses 36,313 37,310 35,670
Depreciation and amortization 12,841 13,470 13,416
Property and payroll taxes 4,574 4,420 3,989
------------- -------------- --------------
53,728 55,200 53,075
------------- -------------- --------------
Earnings from operations 32,339 25,037 25,939
------------- -------------- --------------
Nonoperating Expense (Income)
Interest 10,486 10,132 9,436
Interest charged to construction (383) (550) (532)
------------- -------------- --------------
10,103 9,582 8,904
Amortization of debt issuance expense 603 605 612
Other (495) (388) (467)
------------- -------------- --------------
10,211 9,799 9,049
------------- -------------- --------------
Earnings Before Income Taxes 22,128 15,238 16,890
Income Taxes 8,075 5,694 6,263
------------- -------------- --------------
Net Earnings 14,053 9,544 10,627
Preferred Dividends 483 497 510
------------- -------------- --------------
Net Earnings Available
to Common Shareholders $ 13,570 $ 9,047 $ 10,117
============= ============== ==============
Net Earnings Per Common
Share (basic and diluted) $ 1.23 $ 0.82 $ 0.93
============= ============== ==============
</TABLE>
The accompanying notes are an integral part of these financial statements
21
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
September 30,
-------------------------------------
1999 1998
--------------- ---------------
(Dollars in thousands)
<S> <C> <C>
ASSETS
Utility Plant $ 453,278 $ 433,568
Less accumulated depreciation 177,878 167,356
--------------- ---------------
275,400 266,212
Construction work in progress 6,891 10,394
--------------- ---------------
282,291 276,606
--------------- ---------------
Other Assets
Investments in non utility property 202 667
Notes receivable, less current maturities 577 1,006
--------------- ---------------
779 1,673
--------------- ---------------
Current Assets
Cash and cash equivalents 410 2,338
Accounts receivable, less allowance of
$622 and $645 for doubtful accounts 12,468 9,271
Current maturities of notes receivable 176 329
Materials, supplies, and inventories 6,250 6,213
Prepaid expenses and other assets 5,584 5,122
--------------- ---------------
24,888 23,273
--------------- ---------------
Deferred Charges 7,611 9,959
--------------- ---------------
$ 315,569 $ 311,511
=============== ===============
COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES
Common Shareholders' Equity
Common stock, par value $1 per share
Authorized, 15,000,000 shares; issued and
outstanding, 11,045,095 shares $ 11,045 $ 11,045
Additional paid-in capital 97,380 97,380
Retained earnings 5,970 3,003
--------------- ---------------
114,395 111,428
--------------- ---------------
Redeemable Preferred Stocks, aggregate redemption
Amount of $6,338 and $6,592 6,186 6,408
--------------- ---------------
Long-Term Debt 125,000 110,650
--------------- ---------------
Current Liabilities
Notes payable and commercial paper -- 6,929
Current maturities of long-term debt -- 10,000
Accounts payable 8,933 10,206
Property, payroll, and excise taxes 3,434 4,570
Dividends and interest payable 7,614 7,407
Other current liabilities 4,527 3,681
--------------- ---------------
24,508 42,793
--------------- ---------------
Deferred Credits and Other
Gas cost changes 12,210 10,330
Income taxes 19,405 17,598
Investment tax credits 2,302 2,523
Other 11,563 9,781
--------------- ---------------
45,480 40,232
--------------- ---------------
Commitments and Contingencies (Note 12) -- --
--------------- ---------------
$ 315,569 $ 311,511
=============== ===============
</TABLE>
The accompanying notes are an integral part of these financial statements
22
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
(Dollars in thousands except per share data) Common Stock
--------------------------- Paid-In Retained
Shares Par Value Capital Earnings
------------- ------------ ------------ ----------
<S> <C> <C> <C> <C>
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
Common stock issued:
Employee savings plan and
retirement trust (401(k)) 25,446 25 404
Dividend reinvestment plan 52,917 53 834
Cash dividends:
Common stock, $.96 per share (10,597)
Preferred stock, senior, $.55 per share (26)
7.85% cumulative preferred stock,
$7.85 per share (471)
Net earnings 9,544
------------- ------------ ------------ ----------
Balance, September 30, 1998 11,045,095 11,045 97,380 3,003
Cash dividends:
Common stock, $.96 per share (10,603)
Preferred stock, senior, $.55 per share (12)
7.85% cumulative preferred stock,
$7.85 per share (471)
Net earnings 14,053
------------- ------------ ------------ ----------
Balance, September 30, 1999 11,045,095 $ 11,045 $ 97,380 $ 5,970
============= ============ ============ ==========
</TABLE>
The accompanying notes are an integral part of these financial statements
23
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------------------------
1999 1998 1997
------------ ----------- -----------
<S> <C> <C> <C>
Operating Activities
Net earnings $ 14,053 $ 9,544 $ 10,627
Adjustments to reconcile net earnings to
net cash provided by operating activities:
Depreciation and amortization 12,841 13,470 13,416
Deferrals of gas cost changes 818 4,463 (12,815)
Amortization of gas cost changes 1,062 (424) (2,473)
Other deferrals and amortizations 2,359 1,802 1,860
Deferred income taxes and tax credits - net 2,373 1,568 (522)
Other (174) -- --
Change in current assets and liabilities (5,154) 8,141 (10,047)
------------ ----------- -----------
Net cash provided by operating activities 28,178 38,564 46
------------ ----------- -----------
Investing Activities
Capital expenditures (19,942) (25,611) (29,166)
Customer contributions in aid of construction 2,680 1,831 7,540
Other 1,155 862 460
------------ ----------- -----------
Net cash used by investing activities (16,107) (22,918) (21,166)
------------ ----------- -----------
Financing Activities
Issuance of common stock -- 754 1,747
Redemption of preferred stock (222) (222) (216)
Proceeds from long-term debt, net 14,888 -- 19,850
Repayment of long-term debt (10,650) (500) (700)
Changes in notes payable and commercial paper, net (6,929) (5,971) 12,900
Dividends paid (11,086) (10,531) (9,842)
------------ ----------- -----------
Net cash provided (used) by financing activities (13,999) (16,470) 23,739
------------ ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents (1,928) (824) 2,619
Cash and Cash Equivalents
Beginning of year 2,338 3,162 543
------------ ----------- -----------
End of year $ 410 $ 2,338 $ 3,162
============ =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements
24
<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 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, 1999, the Company had approximately 177,162 core customers
and 189 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 18%
of gas deliveries and 70% 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 generation of electricity, processing of
forest products, production of chemicals, refining of crude oil, production of
aluminum, 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.
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 cost, 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. Depreciation of utility plant is computed
using the straight-line method. During 1998, the Company conducted a
depreciation study resulting in a change in depreciation lives effective July 1,
1998. The new asset lives used for computing depreciation range from six to
seventy years, and the weighted average annual depreciation rate decreased from
approximately 3.5% to 3.0%. Based on depreciable assets at the time of the
study, the annual effect of this change on depreciation expense is approximately
$2 million.
Investments in non utility property: This consists primarily of real estate,
carried at the lower of cost or estimated net realizable value.
25
<PAGE>
Notes receivable: Notes receivable includes loans made to customers for the
purchase of energy efficient appliances, which are generally the security for
the loan. The loans have terms ranging from one to ten years at interest rates
varying from 6.5% to 12%.
Materials, supplies and inventories: Materials and supplies for construction,
operations, 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 that 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, 1999 and 1998 include the
following:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998
- -----------------------------------------------------------
<S> <C> <C>
Unamortized loss on
reacquired debt $ 4,497 $ 5,027
Gas cost changes (12,210) (10,330)
Deferred income taxes (4,247) (3,457)
Postretirement benefits
other than pensions 2,436 3,186
Other, net (316) 852
------------ -----------
Net $ (9,840) $ (4,722)
------------ -----------
</TABLE>
Revenue recognition: The Company accrues estimated revenues for gas delivered
but not billed to residential and commercial customers from the meter reading
dates to the end of the accounting period.
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 normalizes temporary differences between book
income and taxable income, with the exception of depreciation differences on
assets placed in service prior to 1981, consistent with the policies of the WUTC
and OPUC. Deferred income taxes are determined according to the provisions of
Statement of Financial Accounting Standards No. 109.
Investment tax credits: Investment tax credits were deferred and are amortized
over the remaining life of the property giving rise to the credit.
26
<PAGE>
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. The following provides additional information with
respect to the Consolidated Statement of Cash Flows:
<TABLE>
<CAPTION>
(Dollars in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Changes in current assets and current liabilities:
Accounts receivable $ (3,196) $ 2,596 $ (221)
Income taxes (165) 2,261 1,183
Inventories (38) (326) 45
Prepaid expenses and other assets (259) (4) (2,858)
Accounts payable and accrued expenses (1,394) 3,782 (8,115)
Other (102) (168) (81)
---------- --------- -----------
Net change in current assets and current liabilities $ (5,154) $ 8,141 $ (10,047)
---------- --------- -----------
Cash payments:
Interest (net of amounts capitalized) $ 9,136 $ 8,303 $ 7,938
Income taxes $ 5,863 $ 1,876 $ 5,606
</TABLE>
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 estimates in measuring certain deferred charges and deferred credits
related to items subject to approval of the WUTC and the OPUC. 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.
Stock-Based Compensation: Compensation cost for stock options is measured as the
excess of the market price of the Company's stock at the date of the grant over
the price the employee must pay to acquire the stock. The Company accounts for
its stock-based compensation using the intrinsic value method prescribed in
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" rather than using the fair-value-based method prescribed under FAS
No. 123, "Accounting for Stock-Based Compensation." The Company has adopted the
disclosure requirements of FAS No. 123. See Note 6 for more information about
the Company's stock-based compensation plan.
New Accounting Standards:
As of the first quarter of fiscal 1999, the Company adopted Statement of
Financial Accounting Standards (FAS) Nos. 130, 131, and 132.
FAS No. 130, entitled "REPORTING COMPREHENSIVE INCOME," 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 have other
comprehensive income, therefore implementation of this standard has not affected
the reporting of its financial information.
FAS No. 131, entitled "DISCLOSURE ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED
INFORMATION," 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. Management views
the Company as operating as a single segment, that of a local distribution
company (LDC) in the Pacific Northwest. Therefore the adoption of this standard
has not changed the Company's financial reporting.
FAS No. 132, entitled "EMPLOYERS' DISCLOSURES ABOUT PENSIONS AND OTHER
POSTRETIREMENT BENEFITS," modifies the disclosure requirements for pensions and
other postretirement benefits, but does not affect the measurement of such
benefits. These disclosure modifications are included in Note 10.
27
<PAGE>
In June 1998, the Financial Accounting Standards Board issued FAS No. 133,
entitled "ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES." This
standard will be effective for fiscal years beginning after June 15, 2000, and
will be adopted by the Company as of October 1, 2000. It requires that the fair
value of all derivative financial instruments be recognized as either assets or
liabilities on the Company's balance sheet. Changes during a period in the fair
value of a derivative instrument would be included in earnings or other
comprehensive income for the period.
The Company is currently evaluating the effects of this standard on its
financial reporting. This evaluation is not complete, but the Company believes
that some of its natural gas supply contracts may meet the technical definition
of derivative instruments, and thus may be subject to the requirements of FAS
No. 133. The Company also believes that, because of rate regulation, derivative
assets and liabilities would be offset by regulatory assets and regulatory
liabilities, and therefore the earnings effect of application of this standard
would not be material.
SOP 98-1. In March 1998, the Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants issued Statement of Position
(SOP) 98-1, "ACCOUNTING FOR THE COSTS OF COMPUTER SOFTWARE DEVELOPED OR OBTAINED
FOR INTERNAL USE". Application of this SOP is required for financial statements
for fiscal years beginning after December 15, 1998, and was adopted by the
Company effective October 1, 1999. The SOP establishes criteria for accounting
for costs as operating expense when incurred, or as a capital expenditure. It
provides that internal and external cost incurred to develop or obtain new
software during the "application development stage" should be capitalized. Other
costs, including preliminary project costs, training, data conversion, and
upgrades and enhancements would be expensed under the provisions of SOP 98-1.
The materiality of this change is dependent upon the magnitude of the costs and
the nature and complexity of specific software development or acquisition
projects incurred in any period. Based on projects planned for fiscal 2000,
management does not expect the application of this standard to have a material
effect on results of operations or financial reporting.
NOTE 3 - EARNINGS PER SHARE
The following table sets forth the calculation of earnings per share as
prescribed in FAS No. 128.
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------------------
(in thousands except per share data)
<S> <C> <C> <C>
Net earnings $ 14,053 $ 9,544 $ 10,627
Less: Preferred dividends 483 497 510
--------------------------------------
Net earnings available to common shareholders $ 13,570 $ 9,047 $ 10,117
--------------------------------------
Weighted average shares outstanding 11,045 11,000 10,842
Plus: Issued on assumed exercise of stock options 1 -- --
--------------------------------------
Weighted average shares outstanding assuming
dilution 11,046 11,000 10,842
--------------------------------------
Basic and diluted earnings per common share $ 1.23 $ 0.82 $ 0.93
--------------------------------------
</TABLE>
The only dilutive securities are the stock options described in Note 5.
28
<PAGE>
NOTE 4 - UTILITY PLANT
Utility plant at September 30, 1999 and 1998 consists of the following
components:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998
- ------------------------------------------------------------
<S> <C> <C>
Distribution plant $ 401,826 $ 381,524
Transmission plant 14,086 14,086
Production plant 1,053 1,053
General plant 32,104 32,863
Intangible plant 212 212
Nondepreciable plant 3,997 3,830
------------ ------------
$ 453,278 $ 433,568
------------ ------------
</TABLE>
NOTE 5 - COMMON STOCK
At September 30, 1999, shares of common stock are reserved for issuance as
follows:
<TABLE>
<CAPTION>
Number
of shares
- -------------------------------------------------------
<S> <C>
Employee Savings Plan and
Retirement Trust (401(k) plan) 119,765
Dividend Reinvestment Plan 51,338
Director Stock Award Plan 4,112
Stock Incentive Plan 150,000
--------------
325,215
--------------
</TABLE>
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. The
Company's practice is to purchase shares on the open market for these plans
rather than issue new shares.
During the quarter ended March 31, 1999, the Company awarded officers, under the
1998 Stock Incentive Plan, grants to purchase 38,000 shares of Cascade common
stock. The exercise price per share was equal to the fair market value of the
stock at the date of grant. Stock options granted at 100% of fair market value
are not recognized as compensation expense. A portion of the options become
exercisable one year after the grant date, and the options are fully exercisable
three years after the grant date.
Holders of Common Stock have 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.
29
<PAGE>
NOTE 6 - STOCK COMPENSATION PLAN
At its annual meeting January 27, 1999, the Company adopted, and shareholders
approved an incentive compensation plan, the 1998 STOCK INCENTIVE PLAN (the
Plan), under which officers and other key management employees may be granted
options to purchase stock. During the second fiscal quarter, the Company awarded
grants to purchase 38,000 shares at an exercise price of $16.50. The grants vest
1/3 per year over three years, and expire five years after the grant date. At
September 30, 1999, no options were exercisable.
The weighted average fair value of options granted during the year are estimated
at $2.43. The fair value was estimated at the date of the grants using a
Black-Scholes option pricing model using the following assumptions: dividend
yield of 4.52%, expected volatility of 21%, risk-free interest rate of 4.60%,
and an expected life of 4 years.
The Company accounts for stock-based compensation using APB Opinion No. 25,
"Accounting for Stock Issued to Employees". Under this method, compensation cost
is recognized on the excess, if any, of the market price of the stock at grant
date over the exercise price of the option. The exercise price of $16.50 per
share was equal to the market price at the grant date, therefore no compensation
expense has been recorded in connection with the Plan. Under FAS No. 123,
"Accounting for Stock-Based Compensation," compensation expense is determined
based on the fair value of the award and is recognized over the vesting period.
Had compensation expense been determined in accordance with FAS 123, the
Company's net earnings would have been reduced from the reported amount of
$14,053,000 to the pro forma amount of $14,033,000. Net earnings per common
share (basic and diluted) would have been $1.23, the same as reported.
NOTE 7 - REDEEMABLE PREFERRED STOCKS
Redeemable preferred stock at September 30, 1999 and 1998 consists of the
following:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998
- ------------------------------------------------------------------------------------------
Shares Amount Shares Amount
<S> <C> <C> <C> <C>
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 21,750 186 46,750 408
----------------------- -----------------------
81,750 $ 6,186 106,750 $ 6,408
----------------------- -----------------------
</TABLE>
Preferred stockholders have preference over common stockholders in dividends and
liquidation rights. The 7.85% cumulative preferred stock was redeemed on
November 1, 1999. The $.55 cumulative senior preferred stock is subject to
minimum annual redemption requirements, with Series C being fully redeemed in
fiscal 2001. The Series B shares were fully redeemed during fiscal 1999. The
Series C 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 are $6,145,000 in fiscal 2000, $73,000 in fiscal 2001, and none
thereafter.
30
<PAGE>
NOTE 8 - NOTES PAYABLE AND COMMERCIAL PAPER
The Company's short-term borrowing needs are met with a $40,000,000 revolving
credit agreement with three of its banks. This agreement expires in September
2000. 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.
<TABLE>
<CAPTION>
September 30
(dollars in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Amount outstanding $ -- $ 6,929 $12,900
Average daily balance outstanding 8,122 6,201 13,666
Average interest rate, excluding commitment fee 5.44% 5.83% 5.94%
Maximum month end amount outstanding 23,713 13,260 21,650
</TABLE>
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 $25,472,000 is available for payment of
dividends as of September 30, 1999.
NOTE 9 - LONG-TERM DEBT
Long-term debt at September 30, 1999 and 1998 consists of the following:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998
- ---------------------------------------------------------------
<S> <C> <C>
6.53% Five Year Term Note
due Dec. 2000 $ -- $ 650
Medium-term notes:
7.18% due Oct. 2004 4,000 4,000
7.32% due Aug. 2004 22,000 22,000
8.38% due Jan. 2005 5,000 5,000
8.35% due Jul. 2005 5,000 5,000
8.50% due Oct. 2006 8,000 8,000
8.06% due Sep. 2012 14,000 14,000
8.10% due Oct. 2012 5,000 5,000
8.11% due Oct. 2012 3,000 3,000
7.95% due Feb. 2013 4,000 4,000
8.01% due Feb. 2013 10,000 10,000
7.95% due Feb. 2013 10,000 10,000
7.48% due Sep. 2027 20,000 20,000
7.098% due Mar. 2029 15,000 --
------------ -------------
Total long-term debt $ 125,000 $ 110,650
------------ -------------
Current maturities of medium-term notes:
5.77% due Dec. 1998 $ -- $ 5,000
5.78% due Dec. 1998 -- 5,000
------------ -------------
$ -- $ 10,000
------------ -------------
</TABLE>
None of the long-term debt includes sinking fund requirements. The $650,000,
6.53% five year term note was paid off in February 1999. Annual obligations for
redemption of long-term debt are as follows: None in fiscal years 2000 through
2003 and $22,000,000 in fiscal year 2004, and $103,000,000 thereafter.
31
<PAGE>
NOTE 10 - 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:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Current tax expense $5,702 $4,126 $6,785
Deferred tax expense 2,594 1,809 (256)
Amortization of deferred
investment tax credits (221) (241) (266)
----------- ----------- -----------
$8,075 $5,694 $6,263
----------- ----------- -----------
</TABLE>
A reconciliation between income taxes calculated at the statutory federal tax
rate and income taxes reflected in the financial statements is as follows:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory federal income tax rate 35% 35% 35%
Income tax calculated at statutory federal rate $ 7,745 $ 5,333 $ 5,911
Increase (decrease) resulting from:
State income tax, net of federal tax benefit 177 117 122
Non-normalized depreciation differences 374 345 380
Amortization of investment tax credits (221) (241) (266)
Other 0 140 116
---------- ---------- -----------
$ 8,075 $ 5,694 $ 6,263
---------- ---------- -----------
Effective tax rate 36.5% 37.4% 37.1%
</TABLE>
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, 1999 and 1998 are as follows:
<TABLE>
<CAPTION>
(dollars in thousands) 1999 1998
- -------------------------------------------------------------------------
<S> <C> <C>
Deferred tax liabilities:
Basis differences on net fixed assets $17,484 $16,096
Debt refinancing costs 1,610 1,797
Retirement benefit obligations 1,092 1,005
------------ -----------
20,186 18,898
------------ -----------
Deferred tax assets:
Valuation reserves -- 470
Retirement benefit obligations 439 531
Provision for doubtful accounts 266 255
Other 76 44
------------ -----------
781 1,300
------------ -----------
Net deferred tax liability $19,405 $17,598
------------ -----------
</TABLE>
32
<PAGE>
NOTE 11 - 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 to fund the plan by contributing an
amount equal to the actuarially determined normal cost plus ten-year
amortization payments towards the unfunded actuarial liability, subject to the
limits on deductible contributions. The Company also 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 are equal
to 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 a trust
sufficient to assure assets held by the trust always exceed the accumulated
benefit obligation for benefits payable by the 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's policy is to fund the plan to the extent allowable under Internal
Revenue Service rules. The following tables set forth the pension and health
care plan disclosures.
COMPONENTS OF NET PERIODIC BENEFIT COST
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
1999 1998 1997 1999 1998 1997
----------------------------- -----------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 1,784 $ 1,584 $ 1,367 $ 434 $ 394 $ 369
Interest cost 2,838 2,617 2,398 1,316 1,201 1,211
Expected return on plan assets (3,346) (2,861) (2,288) (699) (691) (495)
Amortization of transition obligation 106 106 106 657 657 657
Amortization of prior service cost 424 378 352 -- -- --
Recognized net actuarial loss / (gain) 41 76 34 (341) (371) (99)
Special termination benefit 210 369 -- -- -- --
----------------------------- -----------------------------
Net periodic benefit cost $ 2,057 $ 2,269 $ 1,969 $1,367 $1,190 $1,643
----------------------------- -----------------------------
</TABLE>
33
<PAGE>
<TABLE>
<CAPTION>
Pension Benefits Other Benefits
(dollars in thousands) 1999 1998 1999 1998
- ------------------------------------------------------------------------------- -----------------------
<S> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATIONS
Projected benefit obligation at beginning of year $ 39,745 $ 34,212 $ 18,084 $ 17,495
Service cost 1,784 1,584 434 394
Interest cost 2,839 2,617 1,316 1,201
Plan participants' contributions -- -- 21 17
Amendments 592 -- -- --
Termination benefits 210 369 -- --
Benefits paid (1,911) (1,256) (857) (683)
Changes in assumptions (2,673) 3,028 -- --
Actuarial (gain)/loss 301 (809) (718) (340)
----------------------- -----------------------
Projected benefit obligation at end of year $ 40,887 $ 39,745 $ 18,280 $ 18,084
----------------------- -----------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 36,254 $ 34,046 $ 7,966 $ 7,741
Actual return on plan assets 4,646 24 838 (5)
Employer contributions 2,865 3,440 1,173 580
Plan participants' contributions -- -- 21 17
Benefits Paid (1,911) (1,256) (484) (367)
----------------------- -----------------------
Fair value of plan assets at end of year $ 41,854 $ 36,254 $ 9,514 $ 7,966
----------------------- -----------------------
Funded Status $ 967 $ (3,491) $ (8,766) $(10,118)
Unrecognized prior service cost 2,965 2,798 -- --
Unrecognized net (gain)/loss 183 3,896 (1,798) (1,282)
Unrecognized transition obligation 729 834 8,705 9,362
----------------------- -----------------------
Net amount recognized in Consolidated Statements $ 4,844 $ 4,037 $ (1,859) $ (2,038)
----------------------- -----------------------
</TABLE>
<TABLE>
<CAPTION>
WEIGHTED AVERAGE ASSUMPTIONS 1999 1998
-------------------------
<S> <C> <C>
Discount rate 7.75% 7.25%
Average compensation increase 5.00% 5.00%
Expected rate of return on plan assets
Pension plan 9.00% 9.00%
Supplemental executive retirement plan 8.50% 8.50%
Postretirement medical benefit plan 8.75% 8.75%
</TABLE>
HEALTH CARE COST TREND
The assumed health care cost trend rate used in measuring the APBO is 8.5% for
2000, trending down to 5.5% at 2005. A one percent change in the assumed health
care cost trend rate would have the following effects as of September 30, 1999:
<TABLE>
<CAPTION>
One Percentage Point
------------------------
Increase Decrease
-------- --------
(thousands)
<S> <C> <C>
Effect on service and interest cost $ 322 $ (259)
Effect on postretirement benefit obligation $ 2,725 $ (2,248)
</TABLE>
34
<PAGE>
An amendment to the pension plan, effective April 1, 1999, increased the
projected benefit obligation for union employees represented by the collective
bargaining agreement of the International Chemical Workers Union. The amendment
enhances benefits received by these employees.
The special termination benefit for the supplemental retirement plan represents
the recognition of the increase in the projected benefit obligation for three
executives who elected to accept early retirement benefits effective September
30, 1998. The special termination benefit for the retirement plan represents the
recognition of the increase in the projected benefit obligation for five
employees that retired in December 1998 and January 1999.
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 employee's contribution up to 6%
of the employee's compensation, as defined. The Company recognized costs for
contributions to this plan of $810,000, $769,000, and $703,000, for 1999, 1998
and 1997, respectively.
NOTE 12 - COMMITMENTS AND CONTINGENCIES
Gas Service Contracts
The Company has entered into various long-term contracts for natural gas supply,
transportation, storage, and peaking services. These contracts assure that
adequate supplies of gas will be available to provide firm service to core
customers and to meet 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 up to 25
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:
<TABLE>
<CAPTION>
Interstate Storage
Fiscal Year Ending Firm Gas Pipeline and Peaking
September 30 Supply Transportation Service Total
- -----------------------------------------------------------------------------------
(dollars in thousands)
<S> <C> <C> <C> <C>
2000 $ 24,756 $ 25,904 $ 3,123 $53,783
2001 18,719 25,904 3,123 47,746
2002 18,595 25,767 2,735 47,097
2003 18,595 25,767 2,735 47,097
2004 18,595 25,767 2,735 47,097
Thereafter 15,265 265,233 27,352 307,850
------------- -------------- ------------ ------------
$ 114,525 $ 394,342 $41,803 $550,670
------------- -------------- ------------ ------------
</TABLE>
Purchases under these contracts for fiscal 1999, 1998, and 1997, including
commodity purchases, as well as demand charges have been as follows:
<TABLE>
<CAPTION>
Interstate Storage
Firm Gas Pipeline and Peaking
(dollars in thousands) Supply Transportation Service Total
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1999 $ 60,231 $ 30,224 $ 3,786 $ 94,241
1998 $ 47,102 $ 28,901 $ 4,830 $ 80,833
1997 $ 67,329 $ 30,547 $ 4,626 $ 102,502
</TABLE>
35
<PAGE>
Environmental Matters
There are two claims against the Company for as yet unknown costs for clean up
of alleged environmental contamination related to manufactured gas plant sites
that were previously operated by companies, which were subsequently merged into
Cascade. There is currently not enough information available to estimate the
potential liability associated with these claims.
The first claim was received in 1995, and relates to a site in Oregon. An
investigation has shown that contamination does exist, but there has been no
estimate of clean up costs. It is expected that other parties will participate
in the clean up costs, and negotiations are ongoing as to the sharing
arrangement. Through the end of the fiscal year the amounts spent, primarily on
investigation and containment, has been immaterial.
The second claim was received in 1997, and relates to a site in Washington. An
investigation has determined there is evidence of contamination at the site, but
there is also evidence of an oil line, operated by an unrelated party, crossing
the property, which may have also contributed to the contamination. There is no
estimate of possible clean up costs.
Management intends to pursue reimbursement from its insurance carriers, and
recovery from its customers through increased rates, for any remediation costs
for which the Company is determined to be liable. There is precedent for such
recovery through increased rates, as both the WUTC and OPUC have previously
allowed regulated utilities to increase customer rates to recover similar costs.
Litigation
Various lawsuits, claims, and contingent liabilities may arise from time to time
from the conduct of the Company's business. In 1998 the Company was served with
a lawsuit by six plaintiffs, claiming unspecified damages for personal injuries
in connection with carbon monoxide exposure. The plaintiffs were residents of a
house served by the Company at the time of the incident. The Company denies any
responsibility for these injuries, and the parties are engaged in discovery.
There is no estimate of the Company's potential liability for this claim, and
its self-insured retainage with respect to such claims is $1 million. No other
claim 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 some of its computer systems
are not year 2000 compliant. The Company has completed its corrections to
non-compliant systems, implemented these corrections, and continues testing of
these systems. Primarily Company personnel performed the modifications to
existing systems. The expense for these modifications is charged as incurred.
36
<PAGE>
NOTE 13 - 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, 1999 and 1998, of financial instruments whose values are sensitive
to market conditions are set forth in the following table:
<TABLE>
<CAPTION>
1999 1998
------------------------ -------------------------
Carrying Estimated Carrying Estimated
(dollars in thousands) Amount Fair Value Amount Fair Value
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Redeemable Preferred Stock $ 6,186 $ 6,270 $ 6,408 $ 6,525
Long-term Debt $ 125,000 $ 144,893 $ 120,650 $ 142,517
</TABLE>
37
<PAGE>
NOTE 14 - INTERIM RESULTS OF OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
(thousands except Quarter Ended
per share data) 9/30/99 6/30/99 3/31/99 12/31/98
- ---------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $31,706 $42,869 $71,118 $62,917
Gas costs and revenue taxes 19,288 25,577 41,923 35,755
---------- ---------------------- ----------
Operating margin 12,418 17,292 29,195 27,162
Cost of operations 12,712 13,501 13,791 13,724
---------- ---------------------- ----------
Earnings (loss) from operations (294) 3,791 15,404 13,438
Interest and other, net 2,528 2,477 2,584 2,622
---------- ---------------------- ----------
Earnings (loss) before income taxes (2,822) 1,314 12,820 10,816
Income taxes (1,291) 503 4,801 4,062
---------- ---------------------- ----------
Net earnings (loss) (1,531) 811 8,019 6,754
Preferred dividends 120 121 119 123
---------- ---------------------- ----------
Net earnings (loss) available
to Common Shareholders $(1,651) $ 690 $ 7,900 $ 6,631
---------- ---------------------- ----------
Net earnings (loss) per common
share - basic and diluted $ (0.15) $ 0.06 $ 0.72 $ 0.60
---------- ---------------------- ----------
</TABLE>
<TABLE>
<CAPTION>
(thousands except Quarter Ended
per share data) 9/30/98 6/30/98 3/31/98 12/31/97
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $26,129 $36,995 $65,548 $60,984
Gas costs and revenue taxes 13,850 21,527 38,601 35,441
----------- -------------------------------
Operating margin 12,279 15,468 26,947 25,543
Cost of operations 12,781 14,101 14,346 13,972
----------- -------------------------------
Earnings (loss) from operations (502) 1,367 12,601 11,571
Interest and other, net 2,500 2,400 2,415 2,484
----------- -------------------------------
Earnings (loss) before income taxes (3,002) (1,033) 10,186 9,087
Income taxes (1,158) (370) 3,817 3,405
----------- -------------------------------
Net earnings (loss) (1,844) (663) 6,369 5,682
Preferred dividends 124 124 124 125
----------- -------------------------------
Net earnings (loss) available
to Common Shareholders $(1,968) $ (787) $ 6,245 $ 5,557
----------- -------------------------------
Net earnings (loss) per common
share - basic and diluted $ (0.18) $ (0.07) $ 0.57 $ 0.51
----------- -------------------------------
</TABLE>
38
<PAGE>
INDEPENDENT AUDITORS' REPORT ON
FINANCIAL STATEMENT SCHEDULE
Cascade Natural Gas Corporation and subsidiaries
Seattle, Washington
We have audited the consolidated balance sheets of Cascade Natural Gas
Corporation and subsidiaries (the Corporation) as of September 30, 1999 and
1998, and the related consolidated statements of net earnings available to
common shareholders, common shareholders' equity, and cash flows for the years
ended September 30, 1999, 1998, and 1997, and have issued our report thereon
dated November 5, 1999; 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 Corporation'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 5, 1999
39
<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:
September 30, 1997 $ 439 507 417 $ 529
September 30, 1998 $ 529 585 469 $ 645
September 30, 1999 $ 645 686 709 $ 622
Valuation Reserve - Notes Receivable
September 30, 1997 $1,537 183 $1,720
September 30, 1998 $1,720 118 $1,838
September 30, 1999 $1,838 1,838 $ 0
</TABLE>
Note: Accounts written off, net of recoveries
40
<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 made to the information regarding directors under the
caption "Election of Directors" on pages 1 through 3 and the caption "Section
16(a) Beneficial Ownership Reporting Compliance" on pages 4 and 5 of the
Proxy Statement sent to shareholders for the 2000 Annual Meeting (the 2000
Proxy Statement), which information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to the information regarding executive
compensation set forth in the 2000 Proxy Statement under "Executive
Compensation" on pages 7 and 8, "Retirement Plan" on page 9, "Executive
Supplemental Retirement Income Plan" on pages 9 and 10, "Employment
Agreements" on page 10, "Supplemental Benefit Trust" on page 10, "Director
Compensation" on page 11, and under "Compensation Committee Interlocks and
Insider Participation" on page 11, 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 made 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 2000
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 made to the information regarding certain
relationships and transactions under the caption "Compensation Committee
Interlocks and Insider Participation" on page 11 of the 2000 Proxy Statement,
which information is incorporated herein by reference.
41
<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 for the Years Ended September 30, 1999, 1998, and 1997
Consolidated Balance Sheets, September 30, 1999 and 1998
Consolidated Statements of Common Shareholders' Equity for the Years
Ended September 30, 1999, 1998, and 1997
Consolidated Statements of Cash Flows for the Years Ended September 30,
1999, 1998, and 1997
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.
42
<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 20, 1999 By /s/ J. D. Wessling
----------------------- -------------------------------------------
Date J. D. Wessling
Sr. 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.
<TABLE>
<S> <C> <C>
Chairman of the Board,
President and Chief Executive
/s/ W. Brian Matsuyama Officer and Director December 20, 1999
------------------------ (Principal Executive Officer) -----------------
W. Brian Matsuyama Date
Sr. Vice President - Finance,
/s/ J. D. Wessling Chief Financial Officer December 20, 1999
------------------------- (Principal Financial Officer) -----------------
J. D. Wessling Date
Controller and Chief
/s/ James E. Haug Accounting Officer December 20, 1999
------------------------- (Principal Accounting Officer) -----------------
James E. Haug Date
/s/ Melvin C. Clapp Director December 20, 1999
------------------------- -----------------
Melvin C. Clapp Date
/s/ Thomas E. Cronin Director December 20, 1999
------------------------- -----------------
Thomas E. Cronin Date
/s/ David A. Ederer Director December 20, 1999
------------------------- -----------------
David A. Ederer Date
/s/ Howard L. Hubbard Director December 20, 1999
------------------------- -----------------
Howard L. Hubbard Date
/s/ Larry L. Pinnt Director December 20, 1999
------------------------- -----------------
Larry L. Pinnt Date
/s/ Brooks G. Ragen Director December 20, 1999
------------------------- -----------------
Brooks G. Ragen Date
/s/ Mary A. Williams Director December 20, 1999
------------------------- -----------------
Mary A. Williams Date
</TABLE>
43
<PAGE>
INDEX TO EXHIBITS
EXHIBIT
NO. DESCRIPTION
<TABLE>
<CAPTION>
<S> <C>
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 filed July 19, 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 filed July 19, 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 1998 Stock Incentive Plan of the Registrant.* Incorporated by reference
to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the
year ended September 30, 1998.
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
Registrant's Annual Report on Form 10-K for the year ended December 31,
1991.
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, and 10.22. Incorporated by
reference to Exhibit 10.6 to the Registrant's Annual Report on Form
10-K for the year ended September 30, 1997 (1997 Form 10-K).
10.7 Natural Gas Sales Agreement dated November 1, 1998, between Engage
Energy US L.P., and the Registrant.
10.8 Intentionally omitted.
10.9 Intentionally omitted.
44
<PAGE>
10.11 Gas transportation agreement between Pacific Gas Transmission Company
and the Registrant dated as of April 30, 1997. Incorporated by
reference to Exhibit 10.11 to the Registrant's 1997 10-K.
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 Registrant's registration statement
on Form S-2, No. 33-52672 (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.
10.15 Intentionally omitted.
10.16 Intentionally omitted.
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 1997 Form 10-K.
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 (1994 Form 10-K).
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 1994
Form 10-K.
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 1994 Form 10-K.
10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources,
Inc. and the Registrant. Incorporated by reference to Exhibit 10.21 to
the Registrant's 1994 Form 10-K.
10.21.1 Amended Exhibit A, effective October 1, 1999, 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 the Registrant Incorporated by
reference to Exhibit 10.22 to the Registrant's 1994 Form 10-K.
10.22.1 Letter amendment dated September 22, 1999, to Amended and restated
Natural Gas Sales Agreement dated August 17, 1994, between Engage
Energy Canada L.P. and Registrant. A PORTION OF THIS AGREEMENT IS
SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
45
<PAGE>
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
1994 Form 10-K.
10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest
Pipeline Corporation and the Registrant. Incorporated by reference to
Exhibit 10.24 to the Registrant's 1994 Form 10-K.
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 the Registrant. Incorporated
by reference to Exhibit 10.25 to the Registrant's 1994 Form 10-K.
10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between
Tenaska Gas Co., Tenaska Washington Partners, L.P., and the Registrant.
Incorporated by reference to Exhibit 10.26 to the Registrant's 1994
Form 10-K.
10.27 Agreement for Peaking Gas Supply Service dated November 22, 1991,
between Longview Fibre Company and the Registrant. Incorporated by
reference to Exhibit 10.27 to the Registrant's 1994 Form 10-K.
10.27.1 Amendment No. 3 to Agreement for Peaking Gas Supply Service, dated as
of October 2, 1997. Incorporated by reference to Exhibit 10.27.1 to the
Registrant's 1997 Form 10-K.
10.28 Intentionally omitted.
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 Retirement Income 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 Form of employment agreement between the Registrant and W. Brian
Matsuyama, and each other executive officer of the Registrant. *
Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
10.32 Gas Storage Management Agreement, dated November 17, 1999, between
Amoco Energy Trading Corporation, Part of BP Amoco Group, and the
Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR
CONFIDENTIAL TREATMENT.
10.33 Agreement for Jackson Prairie Storage Service, dated October 7, 1999,
between Engage Energy Canada, L.P. and the Registrant. A PORTION OF
THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
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.
</TABLE>
- ------------------------
* Management contract or compensatory plan or arrangement.
46
<PAGE>
Exhibit 10.7
FIRM OR INTERRUPTIBLE
GAS SALES AGREEMENT
GENERAL TERMS AND CONDITIONS
between
ENGAGE ENERGY US, L.P.
as Seller
and
CASCADE NATURAL GAS CORPORATION
as Buyer
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
<S> <C> <C>
ARTICLE 1. DEFINITIONS ...........................................................................................1
ARTICLE 2. CONFIRMATION ..........................................................................................2
ARTICLE 3. QUANTITY ..............................................................................................2
ARTICLE 4. PRICE OF GAS ..........................................................................................5
ARTICLE 5. TERM ..................................................................................................6
ARTICLE 6. DELIVERY POINT; TITLE; RIGHTS OF POSSESSION ...........................................................6
ARTICLE 7. MEASUREMENTS AND TESTS ................................................................................6
ARTICLE 8. QUALITY OF GAS ........................................................................................6
ARTICLE 9. DELIVERY PRESSURE .....................................................................................6
ARTICLE 10. BILLING AND PAYMENT ...................................................................................7
ARTICLE 11. REGULATION ............................................................................................8
ARTICLE 12. WARRANTIES OF TITLE ...................................................................................8
ARTICLE 13. CREDIT WORTHINESS .....................................................................................8
ARTICLE 14. ADDRESSES AND ACCOUNTS ................................................................................9
ARTICLE 15. FORCE MAJEURE ........................................................................................10
ARTICLE 16. TRANSFER AND ASSIGNMENT ..............................................................................11
ARTICLE 17. NON-WAIVER OF FUTURE DEFAULTS ........................................................................11
ARTICLE 18. ENTIRE AGREEMENT .....................................................................................11
ARTICLE 19. LIMITATION ON CLAIMS .................................................................................11
ARTICLE 20. MISCELLANEOUS ........................................................................................12
EXHIBIT A
</TABLE>
<PAGE>
FIRM OR INTERRUPTIBLE GAS SALES AGREEMENT
GENERAL TERMS AND CONDITIONS
___________________ AS OF THIS 1st day of November, 1998, ENGAGE ENERGY US,
L.P., a Delaware limited partnership ("Seller") and CASCADE NATURAL GAS
CORPORATION, a corporation ("Buyer") who may hereinafter be referred to
collectively as "Parties" or individually as "Party":
WITNESSETH:
WHEREAS, the Parties wish to enter into a Gas Sales Agreement
covering the sale, delivery and purchase of gas.
NOW, THEREFORE, in consideration of the premises and mutual
covenants set forth herein, the Parties agree as follows:
1. DEFINITIONS
1.1 The term "Agreement" shall mean these General Terms and
Conditions and the Exhibit "A" hereto in effect from time
to time.
1.2 The term "gas" shall mean any mixture of hydrocarbons or of
hydrocarbons and noncombustible gasses, in a gaseous state,
consisting essentially of methane.
1.3 The term "Btu" shall mean one (1) British thermal unit, which
is the amount of heat required to raise the temperature of one
(1) pound of water one degree (1*) Fahrenheit at sixty degrees
(60*) Fahrenheit.
Btu shall be measured on a dry basis at 14.73 p.s.i.a.
1.4 The term "MMBtu" shall mean one million (1,000,000) British
thermal units.
1.5 The term "Seller's Transporter" shall mean the pipeline
delivering gas at the Delivery Point(s).
1.6 The term "Receiving Pipeline" shall mean the pipeline receiving
gas at the Delivery Point(s) as such pipeline is identified in
Exhibit "A", or absent such Receiving Pipeline, the pipeline
delivering gas at the Delivery Point(s).
1.7 The term "Delivery Point(s)" shall mean the point(s) identified
in Exhibit "A" at which title to the gas is transferred from
Seller to Buyer.
<PAGE>
1.8 The term "Contract Quantity" (i) for each Exhibit "A" applicable
to a firm transaction having a Delivery Period of one month or
less, shall mean a quantity equal to the sum of the Daily
Contract Quantity (as such is set forth in section 3.1 below)
in effect for each day of the Delivery Period of the Exhibit "A"
in question and (ii) for each Exhibit "A" applicable to a firm
transaction having a Delivery Period of more than one month,
shall mean a quantity, determined for each month in the Delivery
Period of such Exhibit "A", equal to the sum of the Daily
Contract Quantity in effect for every day of each month in such
Delivery Period for which there is a Daily Contract Quantity.
1.9 The term "Exhibit "A"" shall mean the confirmation of each
transaction substantially in the form of Exhibit
"A"/Confirmation attached to these General Terms and Conditions
and made a part hereof.
1.10 The term "Delivery Period" shall, for each Exhibit "A", mean the
period of time that deliveries under each such Exhibit "A" are
to be made.
2. CONFIRMATION
2.1 Seller will prepare and immediately transmit by facsimile to
Buyer the Exhibit "A" attributable to each transaction.
2.2 Either Party or both Parties may electronically record any oral
statement made by telephone or otherwise by a representative of
either Party which pertains or may pertain to formation or
performance of a transaction.
3. QUANTITY
3.1 The Exhibit "A" shall set forth the service level (firm or
interruptible) and the daily quantity of gas that the Parties
intend to purchase and sell (the "Daily Contract Quantity")
during the Delivery Period set forth in the Exhibit "A". More
than one Exhibit "A" may be in effect between the Parties from
time to time. Subject to the terms of this Agreement, the
Parties agree to nominate, deliver and purchase such agreed
upon Daily Contract Quantity.
a. If the service level is specified as "interruptible" in the
applicable Exhibit "A", then either party may interrupt the
sale or reduce the quantities to be sold without liability
to the other (except as set forth in section 3.2 below) if
Seller determines that it does not desire to sell gas to
Buyer or Buyer determines
2
<PAGE>
that it does not desire to purchase gas from Seller. The
Parties shall promptly notify each other in the event of
changes in the quantities to be purchased or sold and shall
change their nominations to reflect such changes.
b. If the service level is specified as "firm" in the
applicable Exhibit "A", Seller shall sell and deliver and
Buyer shall purchase and receive each day the Daily Contract
Quantity specified in the applicable Exhibit "A" for the
Delivery Period specified in such Exhibit "A".
1. If, for any Exhibit "A" in effect for firm service,
Seller fails to deliver the Contract Quantity and such
failure is not otherwise excused by any provision of
this Agreement, by operation of law or Buyer's failure
to meet its obligations hereunder, then Seller shall
compensate Buyer for all costs and expenses incurred
by Buyer in acquiring a quantity of gas ("Replacement
Gas"), up to but not in excess of the difference
between the Contract Quantity and the quantity
delivered during the Delivery Period of such Exhibit
"A" (or during each month thereof if the Delivery
Period of such Exhibit "A" exceeds one month), which
are (on a per MMBtu basis) in excess of the price
payable under such Exhibit "A" ("Buyer's Incremental
Costs"). Buyer agrees to use commercially reasonable
efforts to obtain Replacement Gas at the lowest price
available to Buyer. Within thirty (30) days after the
actual quantities delivered by Seller under the
applicable Exhibit "A" (or during each month thereof
if the Delivery Period of such Exhibit "A" exceeds one
month) are confirmed by Receiving Pipeline, Buyer
shall render to Seller a statement of Buyer's
Incremental Costs detailing the difference between the
Contract Quantity and the quantity delivered under
such Exhibit "A" during the period of time in question,
the quantity of Replacement Gas and the costs and
description of costs incurred by Buyer for such
Replacement Gas. Within thirty (30) DAYS of receipt
of Buyer's statement, Seller shall reimburse Buyer for
Buyer's Incremental Costs. Seller's reimbursement
of Buyer's Incremental Costs shall constitute
Buyer's sole and exclusive remedy for Seller's
failure to deliver gas under the Exhibit "A"
during the period of time in question and Seller
shall not, under any circumstances whatsoever, be
liable to Buyer for any
3
<PAGE>
other costs, charges, expenses, losses or damages
(except as provided under Section 3.2 below) of
any nature or kind whatsoever whether direct or
indirect, foreseeable or not foreseeable,
consequential or incidental, arising from or in
any way attributable to or suffered as a result of
Seller's failure to deliver gas pursuant to the
terms of the Exhibit "A" in question and this
Agreement.
If, for any Exhibit "A" in effect for firm service,
Buyer fails to take the Contract Quantity and such
failure is not otherwise excused by any provision
of this Agreement, by operation of law or Seller's
failure to meet its obligations hereunder, and
Seller sells all or a portion of the difference
between the Contract Quantity and the quantity
taken by Buyer under the Exhibit "A" in question
(or during each month thereof if the Delivery
Period of such Exhibit "A" exceeds one month) to
another purchaser at a price less than the
applicable price payable under such Exhibit "A",
Buyer shall compensate Seller for the difference
between the price per MMBtu which would have been
paid to Seller under such Exhibit "A" and the price
per MMBtu paid to Seller by such other purchaser(s)
("Seller's Incremental Costs"). Seller agrees to
use commercially reasonable efforts to sell such
gas at the highest price available to Seller.
Within thirty (30) days after the actual quantities
delivered under the applicable Exhibit "A" during
the period of time in question are confirmed by
Receiving Pipeline, Seller shall render to Buyer a
statement of Seller's Incremental Costs detailing
the difference between the Contract Quantity for
such Exhibit "A" and the quantity of gas taken by
Buyer under such Exhibit "A" during the period of
time in question, the quantity of gas not taken by
Buyer that was sold to another purchaser and the
price Seller received from such other purchaser(s)
for such gas. Buyer shall reimburse Seller for
Seller's Incremental Costs within thirty (30) days
of Buyer's receipt of Seller's invoice for Seller's
Incremental Costs. Buyer's payment of Seller's
Incremental Costs shall constitute Seller's sole
and exclusive remedy for Buyer's failure to take
gas under the Exhibit "A" during the period of time
in question and Buyer shall not, under any
circumstances whatsoever, be liable to Seller for
any other costs, charges, expenses,
4
<PAGE>
losses or damages (except as provided under
Section 3.2 below) of any nature or kind
whatsoever whether direct or indirect, foreseeable
or not foreseeable, consequential or incidental,
arising from or in any way attributable to or
suffered as a result of Buyer's failure to take
gas pursuant to the terms of the Exhibit "A" in
question and this Agreement.
3.2 The Parties agree to fully cooperate to eliminate imbalances
between nominations and deliveries of gas on Seller's
Transporter and Receiving Pipeline. If any scheduling or
imbalance penalties or charges (including, but not limited
to, cash-outs) are imposed upon a Party hereto by Seller's
Transporter or Receiving Pipeline in accordance with the
provisions of its tariff in effect from time to time, as a
result of a Party's failure to deliver or purchase an agreed
upon nominated quantity of gas or as a result of the other
Party's failure to perform any of its obligations hereunder,
then the failing Party shall reimburse the non-failing Party
the dollar amount of such penalties (or the failing Party's
portion thereof) within thirty (30) days following receipt
of an invoice therefor.
4. PRICE OF GAS
4.1 Exhibit(s) "A" in effect from time to time shall state the
price per MMBtu for the gas that is sold by Seller to, Buyer
("Price").
a. Seller shall pay or cause to be paid all taxes
imposed on or with respect to the gas prior to its
delivery at the Delivery Point(s). Buyer shall
pay, or cause to be paid, all taxes on or with
respect to the gas at and after its delivery at
the Delivery Point(s) including, without
limitation, any and all federal, state or local
sales, use, gross receipts, consumption, franchise
fee or other similar fees, taxes or charges that
may arise from or be levied upon a sale under this
Agreement. If Seller is required to remit or pay
such fees, taxes or charges, Buyer shall promptly
reimburse Seller for same.
b. If Buyer is entitled to purchase gas free from any
such taxes or charges, Buyer shall furnish Seller
the necessary exemption or resale certificate
covering the gas delivered hereunder at the
Delivery Point(s). Buyer agrees to indemnify and
hold harmless Seller from any and all costs,
charges and expenses of any nature incurred by
Seller as a result of Seller's reliance on Buyer's
representation of exemption.
5
<PAGE>
5. TERM
5.1 This Agreement shall be effective as of the date first
written above, and, subject to the other provisions hereof,
shall remain in effect until terminated by either Party upon
at least ten (10) days prior written notice given to the
other Party with such termination to be effective as of the
first day of the month following expiration of such ten (10)
day notice period, provided, however, that if an Exhibit "A"
is in effect, termination shall not be effective as to any
Exhibit "A" then in effect until expiration of the Delivery
Period of each such Exhibit "A".
6. DELIVERY POINT(S); TITLE; RIGHTS OF POSSESSION
6.1 Title and right of possession to all gas delivered and sold
hereunder shall pass to Buyer at the Delivery Point(s).
Seller shall be deemed to be in exclusive control and
possession of the gas and shall be fully responsible for and
shall defend and indemnify Buyer, its successors and
assigns, against any damage, loss or injury caused by the
gas prior to the Delivery Point(s). Buyer shall be deemed to
be in exclusive control and possession of the gas and shall
be fully responsible for and shall defend and indemnify
Seller, its successors and assigns, against any damage, loss
or injury caused by the gas at and after the Delivery
Point(s).
7. MEASUREMENTS AND TESTS
7.1 The measurement and testing of the gas sold hereunder shall
be in accordance with the established procedures in use by
Seller's Transporter and applicable to gas delivered at the
Delivery Point(s).
8. QUALITY OF GAS
8.1 All gas delivered under the terms of this Agreement shall at
all times conform to the quality specifications of Seller's
Transporter at the Delivery Point(s), as such specifications
are contained in Seller's Transporter tariff(s) in effect
from time to time (or in Seller's Transporter standard
transportation service agreement if no tariff is
applicable).
9. DELIVERY PRESSURE
9.1 Seller shall deliver the gas at the pressure prevailing in
Seller's Transporter's facilities at the Delivery Point
specified in Exhibit "A".
6
<PAGE>
10. BILLING AND PAYMENT
10.1 On or before the twelfth (12th) day of each month during the
term of this Agreement, Seller shall render a statement to
Buyer for the total quantity of gas delivered to Buyer
during the preceding month and for any other amount due
Seller under this Agreement for which an invoice is not
otherwise provided. Buyer shall pay to Seller, on or before
the twentieth (20th) day of each month, the amount due based
on Seller's statement. All such payments shall be made to
Seller by wire transfer, in immediately available funds,
directed to Seller's account set forth in Article 14 below.
a. To the extent that the actual quantity is not
available to Seller by the twelfth (12th) day of
each month, Seller may bill Buyer based on
nominated quantities, subject to reduction for any
known periods when nominated quantities were not
delivered and subject to later correction based on
actual data. If a statement is rendered based on
nominated quantities rather than actual
quantities, Seller shall render a corrected
statement as soon as possible after actual
quantities are known.
10.2 If presentation of a statement by Seller is delayed after
the twelfth (12th) day of a month, then the time for payment
shall be extended correspondingly, unless Buyer is responsible
for such delay.
10.3 Buyer and Seller shall have the right during normal business
hours, and upon reasonable prior notice, to examine the
books, records and charts of the other Party to the extent
necessary to verify any statement, charge or computation
made pursuant to this Agreement.
10.4 If Buyer fails to pay when due the amount of any statement
rendered by Seller, Seller may immediately suspend
deliveries of gas hereunder and interest on the unpaid
amount shall accrue from the due date until the date of
payment, at the lesser of (i) the then current prime rate of
interest charged by Citibank, N.A. to its best commercial
and industrial borrowers plus two percent (2%) or (ii) the
maximum lawful rate. This Section 10.4 shall not bar either
Party from asserting any other remedy it may have at law or
in equity.
10.5 If Buyer finds, within the later of (i) twenty-four (24)
months after the date of any statement rendered by Seller or
(ii) twenty-four (24) months after the date of any quantity
adjustment by Seller's Transporter, that it has been
overcharged and if Buyer has paid same and makes a claim for
refund within such twenty-four (24) months,
7
<PAGE>
the overcharge, if verified by Seller, shall be refunded
within thirty (30) days, without interest. If Seller finds,
within the later of (i) twenty-four (24) months after the
date of any statement rendered by Seller or (ii) twenty-four
(24) months after the date of any quantity adjustment by
Seller's Transporter, that there has been an undercharge in
the amount billed in such statement, Seller may within such
twenty-four (24) month period submit a statement for such
undercharge to Buyer and Buyer upon verifying the same,
shall pay the undercharge to Seller within thirty (30) days,
without interest. No adjustments shall be made unless the
other Party is notified of a claim prior to the expiration
of the applicable twenty-four (24) month period.
11. REGULATION
11.1 This Agreement shall be subject to all valid applicable and
effective laws, orders, rules, regulations and directives of
all duly constituted Federal, State and local governmental
authorities having jurisdiction.
12. WARRANTIES OF TITLE
12.1 Seller warrants that it has the right to sell all gas
delivered and that such gas is free and clear of all liens,
encumbrances and adverse claims. Seller shall indemnify
Buyer and save it harmless from suits, actions, debts,
accounts, damages, costs, losses and expenses arising from
or out of this warranty.
12.2 OTHER THAN THOSE EXPRESSLY STATED IN THIS AGREEMENT, THERE
ARE NO GUARANTEES OR WARRANTIES, EXPRESS OR IMPLIED, OF
MERCHANTABILITY, FITNESS, OR SUITABILITY OF THE PRODUCT FOR
A PARTICULAR PURPOSE NOTWITHSTANDING ANY COURSE OF
PERFORMANCE, COURSE OF DEALING OR USAGE OF TRADE OR LACK
THEREOF INCONSISTENT WITH THIS PARAGRAPH.
13. CREDIT WORTHINESS
13.1 Prior to the commencement of deliveries and sales of gas
under this Agreement, and at any time and from time to time
thereafter, Buyer shall furnish Seller with credit
information as may be reasonably required to determine
Buyer's credit worthiness. If requested by Seller, Buyer
shall provide Seller with a satisfactory letter of credit,
guarantee or other good and sufficient security of a
continuing nature and in a satisfactory amount, as
determined by Seller in its sole discretion. At any time
Seller may immediately suspend deliveries and sales of gas
to Buyer if Seller, in its sole judgment, determines that
8
<PAGE>
Buyer's ability to pay for gas has become impaired for any
reason. However, Seller may resume deliveries and sales of
gas to Buyer at such time as Buyer has satisfied Seller of
its ability to pay.
14. ADDRESSES AND ACCOUNTS
14.1 Notices and invoices to Buyer under this Agreement shall be
made as follows:
NOTICES:
Cascade Natural Gas Corporation
P.O. Box 24464 Seattle, WA 98124
Attention: Mickey Patton
Fax No.: 206-624-7215
INVOICES:
Cascade Natural Gas Corporation
P.O. Box 24464 Seattle, WA 98124
Attention: Mickey Patton
Fax No.: 206-624-7215
Notices and payments to Seller shall be made as follows:
NOTICES:
Engage Energy US, L.P.
Five Greenway Plaza, Suite 1200
Houston, Texas 77046-0502
Attn: Contract Administration
Fax No.: (713) 877-3583
PAYMENTS:
Engage Energy US, L.P.
Account #: 4071-9415
Citibank, N.A., N.Y., N.Y.
ABA #: 0210-00089
Either Party may change its address or account as
set forth in this Article by written notice to the
other Party. Unless otherwise
9
<PAGE>
provided, all notices given by one Party to the
other shall be sent by certified mail (return
receipt requested), by courier delivery, by hand
delivery or by telegraph or by facsimile and shall
be effective upon receipt. However, routine
communications, including monthly statements, shall
be considered as delivered when mailed, properly
addressed, by ordinary mail. Provided further, a
communication by facsimile shall be deemed received
on the next business day at the point of receipt if
received at such point after four o'clock (4:00)
p.m. or on a Saturday, Sunday or holiday recognized
by the Party receiving the facsimile communication.
15. FORCE MAJEURE
15.1 If either Buyer or Seller is rendered unable wholly or in
part, by force majeure or any other cause of any kind not
reasonably within such Party's control to perform or comply
with any obligation or condition of this Agreement, upon
giving notice and reasonably full particulars to the other
Party within a reasonable time after the event of force
majeure, such obligation or condition shall be suspended
during the continuance of the inability so caused and such
Party shall be relieved of liability and shall suffer no
prejudice for failure to perform the same during such
period; provided, obligations to make payments shall not be
suspended and the cause of suspension (other than strikes or
lockouts) shall be remedied so far as possible with
reasonable dispatch. Settlement of strikes and lockouts
shall be wholly within the discretion of the Party having
the difficulty. The term "force majeure" shall include,
without limitation by the following enumeration, acts of God
and the public enemy; failure or curtailment of
transportation of gas by either Seller's Transporter or
Receiving Pipeline; the elements; fire; accidents;
breakdowns; shutdowns for purposes of necessary repairs or
maintenance; relocation or construction of facilities;
freezing, breakage, accidents or operational failures to
wells, machinery or lines of pipe; inability to obtain
materials, supplies, permits or labor to perform or comply
with any obligation or condition of this Agreement; strikes
and any other industrial, civil or public disturbances; and
restraints of any government or governmental body or
authority, civil or military.
15.2 Notwithstanding the preceding paragraph, if the service
level is specified as firm in the applicable Exhibit "A",
interruption or curtailment of interruptible transportation
by either Receiving Pipeline or Seller's Transporter shall
not be considered an event of force majeure unless firm
transportation by such pipeline(s) is also being interrupted
or curtailed.
10
<PAGE>
16. TRANSFER AND ASSIGNMENT
16.1 Any entity that shall succeed by purchase merger, or
consolidation to the properties, substantially or in their
entirety, of either Party shall be entitled to the rights and
shall be subject to the obligations of its predecessor in
title under this Agreement. No other assignment of this
Agreement or of any rights or obligations hereunder shall be
made by either Party without the written consent of the other
Party, which consent shall not be unreasonably withheld. This
Article 16 shall not prevent either Party from assigning;
pledging or mortgaging its rights hereunder as security for
its indebtedness. This Agreement shall be binding upon and
inure to the benefit of the respective successors and
permitted assigns of the Parties.
17. NON-WAIVER OF FUTURE DEFAULTS
17.1 No waiver by either Party of any one or more defaults by the
other Party in the performance of this Agreement shall
operate or be construed as a waiver of any future default or
defaults, whether of a like or of a different character.
18. ENTIRE AGREEMENT
18.1 This Agreement constitutes the entire agreement between the
Parties for the sale, delivery and purchase of gas as
contemplated herein.
This Agreement supersedes all prior negotiations,
representations, contracts or agreements, either written or
oral, regarding the subject matter hereof. No modification,
alteration, or amendment of this Agreement and/or any Exhibit
"A" in effect shall be binding upon either Party unless
executed in writing by the Party to be bound.
19. LIMITATION ON CLAIMS
19.1 Neither Party shall be liable for any damages for any breach of
this Agreement, unless a claim is presented in writing within
two (2) years after the alleged damages occurred. The claim
shall set forth in full the nature, character, cause, and amount
of the damage.
19.2 NEITHER PARTY HERETO SHALL BE LIABLE TO THE OTHER PARTY FOR ANY
CONSEQUENTIAL, INCIDENTAL OR PUNITIVE DAMAGES ARISING OUT OF, OR
RELATED TO, A BREACH OF THIS AGREEMENT.
11
<PAGE>
20. MISCELLANEOUS
20.1 THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS,
NOTWITHSTANDING ANY CONFLICT OF LAWS PRINCIPLES OF SAID
JURISDICTION THAT MIGHT REQUIRE THE APPLICATION OF THE LAWS
OF ANOTHER JURISDICTION.
20.2 There is no third party beneficiary to this Agreement, and
the provisions of this Agreement shall not impart rights
enforceable by any person, firm or organization not a Party
or not a successor or assignee of a Party to this Agreement.
20.3 This Agreement was prepared jointly by the Parties hereto
and shall not be construed more stringently against either
Party hereto than the other.
20.4 Each Party hereby certifies that its taxpayer identification
number provided below is correct and each shall, upon
request by the other, execute such forms as are necessary to
verify same.
20.5 The Parties represent and warrant that they have full and
complete authority to enter into and to perform this
Agreement. Each person who executes this Agreement on behalf
of a Party represents and warrants that he or she has full
and complete authority to do so and that their Party will be
bound hereby.
20.6 Descriptive headings used herein, if any, are neither part
of this Agreement nor an aid to interpreting it.
12
<PAGE>
IN WITNESS WHEREOF, the Parties have caused these presents to be
executed in duplicate originals by their proper officers duly authorized in that
behalf, as of the date first above written.
ENGAGE ENERGY US, L.P.
Name
By:
Name: Kevin Manuel
Title: Vice President
Taxpayer I.D. #76-052-7677
"Seller"
CASCADE NATURAL GAS CORPORATION
By:
Name: King Oberg
Title: Vice President
Taxpayer I.D. #91-059-9090
"Buyer"
Signature page to Gas Sales Agreement between Engage Energy US, L.P. and
Cascade Natural Gas Corporation dated November 1, 1998.
13
<PAGE>
EXHIBIT 10.21.1
IGI
IGI RESOURCES, INC.
September 24, 1999
Via Facsimile
Ms. Patricia Gable
Cascade Natural Gas Corporation
222 Fairview Avenue
Seattle, WA 98109
RE: Supply Confirmation
Dear Patty:
This is to confirm our arrangement for the term supply and price IGI will sell
to CNG.
Term: October 1, 1999 through and including March 31, 2000
Point: Kingsgate, into PG&E Gas Transmission-Northwest
Volume: 7,446 Dth/Day
Price: $ < * > US per Dth 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 variables and
fuel-in-kind.
Other: A new Exhibit "A" will be forthcoming.
Sincerely,
Diane M. Clark
Manager - Transportation Services
< * > = Redacted
<PAGE>
AMENDED
EXHIBIT "A"
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, 1999
ENDING DATE OF THIS EXHIBIT "A": MARCH 31, 2000
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. The Delivery Point Selling Price shall be equal to < * >
($ < * > U.S. dry) per MMBTU at AECO-C Rub 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: VICE-PRESIDENT GAS SUPPLY
"SELLER"
IGI RESOURCES
BY:
Randy Schultz
Executive Vice President
Chief Operating Officer
< * > = Redacted
<PAGE>
EXHIBIT 10.22.1
GAS TRANSACTION CONFIRMATION
<TABLE>
<S> <C> <C> <C>
1. BUYER: SELLER: GAS TRANS. AG. DATE FORM
EFF. DATE: DELIVERED:
Cascade Natural Gas Corp. Engage Energy Canada, ILP.
October 1, 1995 Sep. 17, 1999
#2350
</TABLE>
2. DETAILS OF TRANSACTIONS:
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Trans.N Start End Quantity/day Price Qual. of Del. Point Del. Rec.
0. Date/Time Date/Time (MMBtu) (Cdn$) Service pipe pipe
(See 3. below) (Int, Firm or EFP)
See Sec 3 See Sec 3 27037 MMBtu See Sec 3 Firm KINGSGATE WEI WEI
</TABLE>
3. SPECIAL PROVISIONS INCLUDING PRICE DETAILS (if any):
1. Commodity Price of Original August 17, 1994 Contract.
Price for Nov. 1/99 - Oct. 31/00 (as per Amending Agreement
dated August 31, 1999) as follows-
a. The Gas Commodity Price to be paid for gas delivered each month
during the period commencing on November 1, 1999 and expiring on
October 31, 2000 shall be calculated as a percentage price
determined under Subsection c below, based upon a weighted
average of the following published prices (the Index Price):
(i) the 'Rocky Mountain' designated supply source into the
Northwest pipeline system, as that price is provided in
the publication entitled, Inside F E R C's Gas Market
Report in the table entitled, "Prices of Spot Gas
Delivered to Pipelines....(per MMBtu dry)", under the
"Northwest Pipeline Corp." entry multiplied by 26%; and
(ii) the "Canadian Border" designated supply source into
the Northwest pipeline system, as that price is
provided in the publication entitled, Inside F E R C's
Gas Market Report in the table entitled, Prices of
Spot Gas Delivered to Pipelines......(per MMBtu dry)
under the "Northwest Pipeline Corp" entry multiplied
by 35%; and
(iii) the AECO "C" & N.I.T. One-Month Spot price as published
by the 'Canadian Gas Price Reporter' in the table
entitled, Canadian Natural Gas Supply Prices under the
column entitled Avg in U.S$/MMBtu multiplied by 39%.
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.
c. The percentage of the Index Price shall be 86.5%.
2. PRICE CONVERSION:
i) Nov. 1/99 - Mar. 31/00
Price conversion transacted on August 30, 1999 for 25,000
MMBtu/Day (Firm/Fixed Obligation)
Price = US $ < * > per MMBtu
Volume greater than 25,001 MMBtu/Day up to 27,037 MMBtu/Day
is firm delivery based on original pricing as per Section 1
above.
ii) Apr. 1/00 - Oct. 31/00
Price Conversion transacted on August 30, 1999 for volumes 15,000
MMBtu/Day (Firm/Fixed Obligation)
Price = US $ < * > per MMBtu.
Volume greater than 15,001 MMBtu/Day up to 27,037 MMBtu/Day is
firm delivery based on original pricing as per Section 1 above.
3. LOAD FACTOR COMMITMENT
i) All price conversion volumes dictate a 100% minimum load factor.
Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W.,
Calgary, Alberta, Canada T2P 4K9
Phone: (403) 297-0333 Fax: (403) 269-5909
< * > = Redacted
<PAGE>
4. ADDRESSES, OPERATIONS AND BILLINGS AND PAYMENT INFORMATION:
Engage Energy Canada, L.P. Cascade Natural Gas Corp. ("Customer")
1100, 421 - 7th Avenue S.W. 222 Fairview Avenue North
Calgary, Alberta Seattle WA 98109
Canada T2P 4K9 U.S.A.
Marketing Representative Name: Marketing Representative:
Jeff Thompson King Oberg
Phone: (403) 297-1838 Phone: (206) 624-3900
Fax: (403) 269-6909 Fax: (206) 624-7215
Accounting Contact: Accounting Contact:
David Spetz
Phone: (403) 297-0386 Phone: (403)
Fax: (403) 269-5909 Fax: (403)
Operations Contact: Operations Contact:
Shelley Nord
Phone: (403) 297-0381 Phone: (403)
Fax: (403) 2694909 Fax: (403)
Wire Transfer Acct. Wire Transfer Acct.
5. (a) The above are the essential binding terms of the transaction in
question. If a formal master physical agreement is in effect between the
parties, then the above confirmation terms are subject to that agreement. In
the event of any conflict between this transaction and the terms of the
formal agreement the terms above prevail. If no formal agreement exists, then
the parties will finalize and sign one, failing which this transaction
remains binding on the parties. Upon finalizing that agreement, the above
transaction will form a part of, and be subject to, that formal agreement.
ENGAGE ENERGY CANADA, L.P. ("Engage") CASCADE NATURAL GAS CORP. ("the
Customer")
Per Jeff A. Thompson Per King Oberg
Vice President Supply and Marketing Vice President
BC/PNW Region
Dated: Sep. 22, 1999 Dated: Oct. 10, 1999
<PAGE>
September 22, 1999
Fax No. (206) 624-7215
Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington
98109
Attention: Mr. King Oberg
Dear Sir:
Re: Gas Transaction Agreement dated October 1, 1995 and
Amended and Restated Natural Gas Sales Agreement Dated August 17, 1994
Attached in duplicate is a letter of agreement confirming the extension of
the current Kingsgate Agreement pricing methodology for the contract year
November 1, 1999 - October 31, 2000.
Also attached in duplicate for your execution is a Gas Transaction
Confirmation form reflecting Cascade's conversion of a portion of the
Kingsgate Agreement Maximum Daily Quantity from a floating price to a fixed
price.
Upon execution, we would appreciate receiving a copy of each for our files.
If you have any questions please call me at (403) 297-1838.
Yours truly,
ENGAGE ENERGY CANADA, LP.
Jeff Thompson
Vice President, Supply and Marketing
British Columbia and Pacific Northwest Region
JATAW Aft.
Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W.,
Calgary, Alberta, Canada T2P 4K9
Phone: (403) 297-0333 Fax: (403) 269-5909
<PAGE>
August 31, 1999
Fax No. (206) 624-7215
Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington 98109
Attention: Mr. King Oberg
Dear Sir:
Re: Amended and Restated Natural Gas Sales Agreement dated August 17, 1994
between Engage Energy Canada, L.P. ("Engage") ("Seller") and Cascade Natural Gas
Corporation ("Cascade") ("Buyer") (The "Kingsgate Agreement")
Further to recent discussions, this letter shall confirm the agreement
between Engage and Cascade to extend the current provisions of Section 7.8 of
the above-referenced agreement for the period November 1, 1999 through
October 31, 2000. For further clarification the terms are 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, 1999 and expiring on October 31,
2000 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 26%; 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 35%; 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
39%.
Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W.,
Calgary, Alberta, Canada T2P 4K9
Phone: (403) 297-0333 Fax: (403) 269-5909
<PAGE>
Cascade Natural Gas Corporation
August 31, 1999
Page 2
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.
c. The percentage of the Index Price shall be determined in accordance with
the following table:
"INDEX PRICE" PERCENTAGE TABLE
Period Quantity of Gas Purchased Applicable
During Period Percentage of "Index
Price"
Nov. 1, 1999 to All quantities purchased 86.5%
Oct. 31, 2000 during period
Engage and Cascade agree to add the following Subsection 4.3 c,
C. Notwithstanding any other provision of this Section 4.3, Buyer shall
purchase from Seller at the Delivery Point, or if not purchased and taken,
shall nevertheless pay for at the Gas Commodity Price specified in Section
7.10 as in effect on the last day of the period, a minimum daily quantity of
gas which shall equal to 15,000 MMBtu.
Terms or phrases defined or used in the Gas Sales Agreement shall have the
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 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. Kathy Puls
Accepted and Agreed to this 10th day of October, 1999.
CASCADE NATURAL GAS CORPORATION
King Oberg
Vice President
<PAGE>
EXHIBIT 10.32
BPAmoco AMOCO ENERGY TRADING CORPORATION
A subsidiary of We BP Amoco Group
501 WestLake Park Boulevard
Houston, Texas 77079
November 17, 1999
Cascade Natural Gas Corporation
222 Fairview Avenue
Seattle, Washington 98109
Attention: Ms. Pattie Grable
STORAGE MANAGEMENT AGREEMENT
Dear Ms. Grable:
This letter documents the storage management agreement between Cascade
Natural Gas Corporation (Cascade) and Amoco Energy Trading Corporation
(AETC), Part of BP Amoco Group, relating to a portion of Cascade's storage
capacity in the Jackson Prairie storage field operated by NWPL.
Contract Term: November 1, 1999 through October 31, 2000,
extendible by mutual agreement.
Storage Capacity: 604,351 MMbtu's
Contracted Withdrawal Capacity: 16,789 MMbtu/D
Bonus Payment: US $ < * > payable by AETC to Cascade on
or before November 24, 1999. The Bonus
Payment is the consideration for Cascade
allowing AETC to manage and use its storage
rights as provided in this agreement.
Optimization Profit Sharing: In the event AETC recovers 100% of the
Bonus Payment, as optimization profits
generated by its storage and cycling
activities during the Contract Term, any
additional such optimization profits shall
be shared between AETC (< * > %) and Cascade
(< * > %), payable within thirty (30) days
after the end of the Contract term.
< * > = Redacted
<PAGE>
CASCADE'S STORAGE MANAGEMENT AGREEMENT
NOVEMBER 17, 1999
PAGE 2 OF 4
Winter Priority: Cascade shall retain the right to call on
up to 604,351 MMbtu's of storage gas
between November 1, 1999 through March 31,
2000. As such, AETCs right to cycle storage
during this winter period shall be
subordinated to Cascade's right to withdraw
up to 604,351 MMbtu's during this period.
Any AETC winter cycling activity shall be
designed not to infringe upon Cascade's
contract withdrawal rights as stated above.
Summer Refill: It is the intent of the parties that AETC
during the contract term will manage the
refill of Cascade's storage capacity, in
compliance with tariff inventory capacity
targets, redelivering to Cascade 604,351
MMbtu's in the storage account at the end
of the Contract Term. AETC will cause
refill gas to be injected more or less
ratably during the summer injection season.
Cascade's ratable daily refill will be
determined by dividing the cumulative
volume withdrawn by Cascade through 3/31/00
by 183 days (i.e., up to 604,351 MMbtu's
divided by 183 days equals 3,302 Mmbtud).
In addition, with notice to AETC at least 5
business days prior to the beginning of the
month, Cascade may request that AETC refill
at a daily quantity of up to 125% of the
ratable daily refill quantity for such
month. For the 604,351 MMbtu's of supply,
Cascade shall pay AETC the pertinent
I.F.E.R.C. NWPL first of month index price
plus applicable transportation and storage
costs incurred by AETC. Cascade may elect,
from time to time, to convert such first of
month index price to either a) a fixed
price for one or more future months, or b)
a daily price tied to Gas Daily index
prices. If Cascade wants a quote for either
such price, it shall notify AETC at least 5
business days prior to the beginning of the
applicable month. AETC shall provide
Cascade a quote as soon as possible for the
requested pricing alterative(s) (a fixed
price or the Gas Daily average price for
the upcoming month) adjusted to reflect
market conditions. At that time, Cascade
shall be available to verbally respond
immediately to the quote provided by AETC
and to elect whether to accept the
alternative pricing. A verbal acceptance by
Cascade shall be binding upon the parties,
and AETC shall promptly confirm by
facsimile Cascade's acceptance of the
alternative pricing quote. If Cascade does
not accept the
<PAGE>
CASCADE'S STORAGE MANAGEMENT AGREEMENT
NOVEMBER 17, 1999
PAGE 3 OF 4
alternative pricing, then the aforesaid
I.F.E.R.C. based price shall be the price
for that month. Upon request, AETC will
apprise Cascade of inventory volumes and
WACOG.
Operations: Cascade shall make its nominations to and
from the Jackson Prairie storage account
directly to AETC. Cascade shall designate
AETC as its Agent for nominations to
Williams Pipeline - West regarding Cascade's
storage account applicable to this
agreement. Cascade and AETC shall
coordinate actual activities associated
with the Jackson Prairie storage facility,
including operating practices ensuring
Cascade's nominations to AETC in a timely
manner for AETC to be compliant with all
Gas Industry Standards Board requirements.
However, Cascade will not have the right or
ability to dictate the manner in which AETC
uses or cycles the Jackson Prairie storage
account unless the activities of AETC can
be demonstrated to adversely impact
Cascade's right to call on winter gas as
stated in Winter Priority, above. Cascade
and AETC will cooperate to minimize the
number and severity of renominations.
Storage and Transport Costs: Cascade shall continue to bear all fixed
transportation and storage charges related
to the storage capacity, and all variable
transportation and storage charges
(including commodity and fuel charges)
relating to the withdrawal and refill of up
to 604,351 MMbtu's. AETC shall pay all
other variable costs (including commodity
and fuel charges) it incurs in the conduct
of its storage cycling activities.
Value of Storage Cycling: The value of storage management to AETC
(and to Cascade once AETC recovers the
Bonus Payment through optimization) arises
from taking advantage of cycling
opportunities whenever market conditions
permit.
<PAGE>
CASCADE'S STORAGE MANAGEMENT AGREEMENT
NOVEMBER 17, 1999
PAGE 4 OF 4
Availability of TF-2 Transport: November 1, 1999 through September 30, 2000
(and possibly during October 2000 but only
with Cascade's prior consent). During the
period November 1, 1999 through March 31,
2000, AETC's right to use TF-2 transport as
agent for Cascade pursuant to this
agreement will be subordinated to Cascade's
right to transport up to 16,739 MMbtud.
Cascade and AETC can mutually agree to
allow AETC such use of TF-2 capacity. Use
of such capacity by AETC will preclude any
responsibility on AETC's part to reimburse
Cascade for TF-2 transport costs other than
applicable volumetric charges.
This letter constitutes the agreement between the parties for storage management
services as specified above.
Sincerely,
AMOCO ENERGY TRADING CORPORATION
By V
James A. Taylor
Regional Vice President - West
Agreed to and accepted this 25th day of November, 1999
CASCADE NATURAL GAS COMPANY
By
Name: KING OBERG
Title: VICE PRESIDENT, GAS SUPPLY
<PAGE>
EXHIBIT 10.33
ENGAGE
October 7, 1999
Via Telecopy
Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington 98109-5312
Attn: Mr. King Oberg
Vice-President, Gas Supply
Dear King:
Re: Jackson Prairie Storage Service
This letter outlines the terms and conditions under which Engage Energy Canada,
L.P. ("Engage") would be prepared to purchase storage services from Cascade
Natural Gas ("Cascade") for the upcoming contract year.
Term: November 1, 1999, through October 31, 2000
Volume: Inventory: 480,000 MMBtu
Withdrawal: Firm 15,000 MMBtutday
Best efforts 5,533 MMBtu/day
Price: Unconditional, up-front payment of $ < * >
(est. < * > % of total demand and capacity demand
charges).
Revenue Sharing: < * > % over the term of the agreement. The
Revenue Sharing plan will be based solely upon
Secondary Call volumes and replacements, and not
applicable to the 15 days maximum of Engage Firm Call
volumes and replacements. All withdrawals and
replacements made by Engage shall be recorded
separately from all other Engage business and will be
subject to audit by Cascade upon request.
Firm Call: Engage shall have the first right to call on a maximum
of 10,000 MMBtu/day from Cascade, not more that 5 days
per month, or more than 15 days over the Firm Call
Period (November 1, 1999, through March 31, 2000). For
volumes specified as Firm Call Cascade shall be
obligated to deliver one hundred (100%) percent of the
requested quantity. Similarly, Engage shall be
obligated to take all volumes specified as Firm Call
volumes. Further, on the days in which Engage nominates
Firm Call volumes, Engage will not request best efforts
volumes.
Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W,
Calgary, Alberta, Canada T2P 4K9
Phone: (403) 297-0333 Fax: (403) 269-5909
< * > = Redacted
<PAGE>
Cascade Natural Gas
October 7, 1999
Page 2
Secondary Call: Engage shall have the ability to call on a maximum of
15,000 MMBtu/day (firm withdrawal quantity) and up to
5,533 MMBtu/day (best efforts quantity) from Cascade
over the period. Engage recognizes that Cascade has
the first right to call on these volumes, and provides
the Secondary Call to Engage on a best-efforts basis
only.
Transportation: For all Firm Call volumes, Engage will have the first
right to request delivery of Jackson Prairie
withdrawal volumes under Cascade's TF-2
transportation. Engage will reimburse Cascade for all
TF-2 commodity charges incurred during the periods in
which Engage utilizes, such transportation. Engage
may also elect to transport Firm Call volumes under
its TF-1 service.
For all Secondary Call volumes, Engage may request
on a best efforts basis delivery of Jackson
Prairie withdrawal volumes under Cascade's TF-2
transportation. Engage will be reimbursed by Cascade
for all TF-2 commodity charges incurred during the
periods in which Engage utilizes such
transportation. Engage may also elect to transport
Secondary Call volumes under its TF-1 service.
Engage recognizes that Cascade's TF-2 transportation
is limited in volume to the equivalent of 1
withdrawal cycle (480,000 MM8tu total), and once
utilized is no longer available until the next
storage period (November 1, 2000, through October
31, 2001).
Replacements: Engage will replace all volumes withdrawn prior to
September 30, 2000. All costs associated with the
volume replacement will be Engage's responsibility.
We hope this proposal will meet with your approval. This offer is open for
acceptance until the close of business on October 8, 1999. Following this date,
the proposals contained herein will be deemed to be expired. If you have any
questions, please contact me at (503) 471-1333.
Yours truly,
ENGAGE ENERGY CANADA, L.P.
Fred M. Scott, P.Eng.
Director, Business Development
Agreed to and accepted to this 7th day of October 1999.
<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
----------------------------------------------------------------------
30-Sep-99 30-Sep-98 30-Sep-97 30-Sep-96 31-Dec-95
-------------- ------------- ------------- ------------ ------------
(dollars in thousands)
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest expense $ 10,486 $ 10,132 $ 9,436 $ 10,101 $ 9,938
Amortization of debt
issuance expense 603 605 612 612 606
-------------- ------------- ------------- ------------ ------------
Total fixed charges $ 11,089 $ 10,737 $ 10,048 $ 10,713 $ 10,544
-------------- ------------- ------------- ------------ ------------
Earnings, as defined:
Net earnings $ 14,053 $ 9,544 $ 10,627 $ 8,211 $ 7,732
Add (deduct):
Income taxes 8,075 5,694 6,263 4,272 4,508
Fixed charges 11,089 10,737 10,048 10,713 10,544
-------------- ------------- ------------- ------------ ------------
Total earnings $ 33,217 $ 25,975 $ 26,938 $ 23,196 $ 22,784
-------------- ------------- ------------- ------------ ------------
Ratio of earnings to
fixed charges 3.00 2.42 2.68 2.17 2.16
============== ============= ============= ============ ============
Fixed charges and preferred dividend requirements:
Fixed charges $ 11,089 $ 10,737 $ 10,048 $ 10,713 $ 10,544
Preferred dividend
requirements 756 778 811 819 853
-------------- ------------- ------------- ------------ ------------
Total $ 11,845 $ 11,515 $ 10,859 $ 11,532 $ 11,397
-------------- ------------- ------------- ------------ ------------
Ratio of earnings to fixed charges and
preferred dividend requirements 2.80 2.26 2.48 2.01 2.00
============== ============= ============= ============ ============
</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, No. 33-39873 and No. 333-88419 on Form S-8 of Cascade Natural Gas
Corporation, of our reports dated November 5, 1999, appearing in this Annual
Report on Form 10-K of Cascade Natural Gas Corporation for the year ended
September 30, 1999.
DELOITTE & TOUCHE LLP
Seattle, Washington
December 20, 1999
<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 YEAR ENDED SEPTEMBER 30, 1999, 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-30-1999
<PERIOD-START> OCT-01-1998
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 282,291
<OTHER-PROPERTY-AND-INVEST> 779
<TOTAL-CURRENT-ASSETS> 24,888
<TOTAL-DEFERRED-CHARGES> 7,611
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 315,569
<COMMON> 11,045
<CAPITAL-SURPLUS-PAID-IN> 97,380
<RETAINED-EARNINGS> 5,970
<TOTAL-COMMON-STOCKHOLDERS-EQ> 114,395
6,186
0
<LONG-TERM-DEBT-NET> 125,000
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 69,988
<TOT-CAPITALIZATION-AND-LIAB> 315,569
<GROSS-OPERATING-REVENUE> 208,610
<INCOME-TAX-EXPENSE> 8,075
<OTHER-OPERATING-EXPENSES> 176,271
<TOTAL-OPERATING-EXPENSES> 176,271
<OPERATING-INCOME-LOSS> 32,339
<OTHER-INCOME-NET> 495
<INCOME-BEFORE-INTEREST-EXPEN> 24,759
<TOTAL-INTEREST-EXPENSE> 10,706
<NET-INCOME> 14,053
483
<EARNINGS-AVAILABLE-FOR-COMM> 13,570
<COMMON-STOCK-DIVIDENDS> 10,603
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 28,178
<EPS-BASIC> 1.23
<EPS-DILUTED> 1.23
</TABLE>
