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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 [FEE REQUIRED]
For the fiscal year ended December 31, 1995 Commission file number: 1-7196
CASCADE NATURAL GAS CORPORATION
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 including area code)
executive office)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of each Exchange on which Registered
- -------------------- -----------------------------------------
Common Stock, Par Value $1 per Share New York Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No ____
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant as of the close of business on February 29, 1996, was $141,782,141.
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 9,184,992 as of February 29, 1996
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for its 1996 Annual
Meeting of Shareholders are incorporated by reference into Part III, Items
10, 11, 12, and 13.
CASCADE NATURAL GAS CORPORATION
ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION ON FORM 10-K
For the Year Ended December 31, 1995
Table of Contents
Page Number
-----------
Part I
Item 1 - Business 3
Item 2 - Properties 12
Item 3 - Legal Proceedings 12
Item 4 - Submission of Matters to a Vote of Security Holders 12
Executive Officers of the Registrant 13
Part II
Item 5 - Market for Registrant's Common Equity and
Related Stockholder Matters 14
Item 6 - Selected Financial Data 15
Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations 17
Item 8 - Financial Statements and Supplementary Data 21
Item 9 - Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 43
Part III
Item 10 - Directors and Executive Officers of the Registrant 44
Item 11 - Executive Compensation 44
Item 12 - Security Ownership of Certain Beneficial Owners
and Management 44
Item 13 - Certain Relationships and Related Transactions 44
Part IV
Item 14 - Exhibits, Financial Statement Schedules and
Reports on Form 8-K 45
Signatures 46
Index to Exhibits 47
2
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 19% of its gas distribution
revenues are from the state of Oregon.
At December 31, 1995, there were 126,886 residential customers, 23,641
commercial customers, 337 firm industrial customers and 25 traditional
interruptible customers, all of which are classified as core customers. In
addition, there were 116 non-core customers. In 1995, the core customers
provided 69% of the operating margin, the same ratio as in 1994, while
consuming 24% of the total gas deliveries, down from 25% in 1994. The
non-core customers (including transportation service) provided the remaining
operating margin and throughput.
Cascade's gas supply contracts provide for annual review of gas prices
for possible adjustment. To the extent that prices are changed, 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.
The Company is also subject to state regulation with respect to
integrated resource planning and has filed its Integrated Resource Plan (IRP)
with both the Washington Utilities and Transportation Commission (WUTC) and
the Oregon Public Utility Commission (OPUC). The IRP shows the Company's
plan for the best set of supply and demand side resources that minimizes
costs and has acceptable levels of deliverability risk over the twenty-year
planning horizon. The IRP also sets forth the Company's forecast of growth
in customers and volume throughput for a twenty-year period. In addition,
the IRP sets forth the Company's demand side management goals of achieving
certain conservation levels in customer usage. The Company's investments in
cost-effective demand side resources are recoverable in rates in both
Washington and Oregon.
The IRP also sets forth the Company's supply side management plans
regarding transportation capacity and gas supply acquisition over a
twenty-year period. The Company developed the IRP over a two-year period and
took into account input solicited from the public and the WUTC and OPUC
staffs. While the filing of the IRP with both commissions gives the Company
no advance assurance that its acquisitions of pipeline transportation
capacity and gas supplies will be recognized in rates, management believes
that the integrated resource planning process benefits the Company by giving
it the opportunity to obtain input from regulators and the public
concurrently with making these important strategic decisions.
Until the Company receives final regulatory approval of these decisions
in the context of a rate case, the Company cannot predict with certainty the
extent to which the integrated resource planning process will affect its
rates.
3
The principal industrial activities in Cascade's service area include
the production of pulp, paper and converted paper products, plywood, chemical
fertilizers, industrial chemicals, cement, clay and ceramic products,
textiles, refining of crude oil, smelting and forming of aluminum, the
processing and canning of many types of vegetable, fruit and fish products,
processing of milk products, meat processing and the drying and curing of
wood and agricultural products.
NATURAL GAS SUPPLY
The majority of Cascade's supply of natural gas is transported via
Northwest Pipeline Corporation (Northwest). Northwest owns and operates a
transmission system extending from points of interconnection with El Paso
Natural Gas Company and Transwestern Pipeline Company near Blanco, New Mexico
through the states of New Mexico, Colorado, Utah, Wyoming, Idaho, Oregon and
Washington to the Canadian border near Sumas, Washington. Natural Gas is
transported north from the Colorado and New Mexico area, and south from
British Columbia, Canada. The Company is also a shipper on the Pacific Gas
Transmission Company (PGT) system. PGT owns and operates a gas transmission
line that connects with the gas fields in Alberta, Canada at the
international border and extends through Washington and central Oregon into
California.
On November 1, 1993, Northwest completed the process, begun in 1988, of
converting its sales function to firm transportation service. Along with the
sales conversion of its remaining sales service from Northwest, the Company
accepted assignment of a pro-rata share of Northwest's remaining Canadian gas
supply arrangements, an equivalent share of PGT firm pipeline transportation
and a portion of Northwest's natural gas inventory at the Clay Basin Storage
Facility. (The Clay Basin inventory was completely withdrawn by March 31,
1995 according to a schedule dictated by the assignment agreement.)
Presently, baseload requirements for Cascade's core market group are
provided by seven major gas supply contracts with various expiration dates
from 1996 through 2008 and totaling 865,010 therms per day. Approximately
82% of the gas supplied pursuant to the contracts is from Canadian sources.
The remainder is domestic. These contracts are supplemented by various
service agreements to cover periods of peak demand including three storage
agreements with Northwest. One extends to October 31, 2014 and provides for
165,950 therms per day and a maximum, renewable inventory of 5,973,780
therms. The second, with The Washington Water Power Company (WWP), had a
primary term extending to April 30, 1995 and entitles Cascade to receive up
to 150,000 therms per day and a maximum, renewal inventory of 4,800,000
therms. Earlier in 1995 Cascade accepted an offer from WWP to extend the
primary term of the agreement by three years through April 1998. A third
contract for liquefied natural gas ("LNG") storage is available through
October 31, 2014. Under this LNG agreement, Cascade is entitled to receive
up to 600,000 therms per day to a maximum, renewable inventory of 5,622,000
therms. In addition to withdrawal and inventory capacity, Cascade also
maintains a corresponding amount of firm transportation from the storage
facility to the city gate for each of these agreements.
Cascade also owns a propane air peak shaving plant with revised daily
capacity of 30,000 therms.
4
In addition to underground and LNG storage, Cascade has entered into
contracts with two of its major industrial customers whereby the customer
agrees to switch to alternate fuel allowing Cascade to reduce firm deliveries
to that customer. One such peak shaving agreement entitles Cascade to call
upon 150,000 therms per day up to a seasonal total of 3,000,000 therms. This
contract expires on September 30, 2015. The second peak shaving agreement,
which expires on September 30, 2014, entitles Cascade to call on a maximum of
up to 500,000 therms per day and up to a seasonal total of 3,000,000 therms.
Commencing December 1995 Cascade entered into two peaking service
agreements with Canadian gas suppliers. These agreements provide for a
maximum daily quantity of 250,000 therms on peak and renewable inventory of
5,500,000 therms. Cascade can call upon these two service agreements any day
during the peak winter months of December, January and February. These
service agreements, while less reliable than firm storage service, are more
flexible than baseload gas supply contracts: both agreements allow for same
day nomination, and city gate delivery at a competitive cost. Each agreement
has a primary term of three years.
Cascade maintains a diversified portfolio of natural gas supplies.
During 1995, Cascade purchased gas supplies approximately 69.9% from firm gas
supply contracts, 28.7% from 30-day spot market contracts and 1.4% from
customer assigned gas purchase contracts. In addition, 416,225,000 therms
of customer purchased supplies were transported across Cascade facilities.
CURRENT FEDERAL ENERGY REGULATORY COMMISSION (FERC) MATTERS
The FERC issued an order on December 20, 1994 confirming an earlier
order reallocating the direct billed gas supply take or pay contract
restructuring costs among Northwest Pipeline Corporation's (Northwest)
customers. The FERC order gave Cascade an obligation of $4.8 million,
approximately $1.8 million above the allocation method favored by the
Company. Cascade joined with others and appealed the order to the D. C.
Circuit Court. It does not appear that the Court will overturn the FERC order
and Cascade is no longer taking an active part in appealing the order. To the
extent Cascade's final allocation differs from the original, it will seek to
pass on the difference to its customers.
On May 3, 1994, Northwest filed a general Section 4 rate case (RP94-220)
seeking additional revenues of $22.5 million. The filing reflected a cost of
service of $240 million. Settlement discussions between the various shippers
and Northwest concluded in early October 1995, with a negotiated cost of
service of $222 million. The settlement was filed on November 14, 1995, with
rates effective on November 1, 1995. Northwest preceded the RP94-220
settlement with another general Section 4 rate case (RP95-409) on August 1,
1995, with interim rates subject to refund, and effective February 1, 1996.
The new filing asks for a cost of service of $270 million. Settlement
discussions are currently being scheduled.
On May 31, 1995 the FERC issued a Statement of Policy (PL94-4) for the
rate treatment of new and existing facilities constructed by interstate
natural gas pipelines. The policy concerns the
5
question of whether to utilize a rolled in methodology or an incremental rate
design. According to the Statement of Policy, the FERC will apply a
presumption in favor of rolled in rates when the increase to existing
customers is 5% or less, and the pipeline makes a showing of system-wide
benefits. Pipelines not meeting the 5% test must show benefits proportionate
to the rate impact for the presumption of rolled in rates. Although not
final, this ruling will have a major influence in the rate methodology
utilized in the current and future Northwest Pipeline Corporation and Pacific
Gas Transmission Company rate cases
COST OF PURCHASED GAS
Following the implementation of Order 636, 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 service.
CURTAILMENT PROCEDURES
In previous heating seasons, cold weather has required Cascade to
significantly curtail its interruptible customers. Cascade has not curtailed
any firm customers, except under force majeure provisions. Cascade's tariffs
effective in Washington and Oregon, allow for curtailment of interruptible
services, which are provided at rates lower than for firm services. In the
event of curtailment by Cascade of firm service due to force majeure,
Cascade's tariffs provide that it shall not be liable for damages or
otherwise to any customer for failure to deliver gas curtailed in accordance
with the provisions of the tariffs. The tariffs provide for appropriate
adjustment of the monthly bill of firm customers curtailed by reason of an
insufficient supply of gas.
TERRITORY SERVED AND FRANCHISES
The population of communities served by Cascade totaled approximately
744,000 at the end of 1995 compared to 724,000 at the end of 1994, a 2.8%
increase.
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 1996 to 2065. Management
has not incurred significant difficulties in renewing franchises when they
expire and does not expect any significant problems in the future.
6
CUSTOMERS
Residential and commercial customers principally use natural gas for
space heating and water heating. This market is very weather-sensitive. See
"Seasonality," below.
Of its non-core customers, 15 accounted for approximately 18% of
Cascade's total 1995 gas and transportation revenues. Agreements with its
principal industrial customers are for fixed terms of not less than one year
and provide for automatic extension from year to year unless terminated by
either party on 30-days' notice. See Note 12 under Notes to Consolidated
Financial Statements, for information regarding revenues from a major
customer.
SEASONALITY
Weather is an important factor affecting gas revenues because of the
large number of customers using gas for space heating. In 1995, 66.5% of
operating revenues and 99.4% of earnings from operations were derived from
the first and last quarters. Because of the seasonality of space heating
revenues, Cascade believes financial results for interim periods are not
necessarily indicative of results to be expected for the year.
COMPETITIVE CONDITIONS
Cascade operates in a competitive market for natural gas service.
Cascade competes with residual fuel oil and other alternative energy sources
for industrial boiler uses, and oil and electricity for residential and
commercial space heating, and electricity for water heating.
Competition is primarily based on price. For residential and commercial
space heating use, Cascade continues to maintain a price advantage over oil
in its entire service territory and has an advantage over electricity in over
96% (by population) of its territory. In the remaining areas of its service
territory served by public electric utilities with their own substantial
hydro power supply, Cascade is near parity with respect to electricity
furnished by those utilities for space heating and water heating uses.
Through its wholly-owned subsidiary, Cascade Land Leasing Co., the Company
provides loans to customers to finance the purchase and installation of
energy efficient gas appliances.
Historically, the large volume industrial market was very sensitive to
price fluctuations between the comparable cost of natural gas and alternate
fuels, principally residual fuel oil used in boiler applications. However,
the advent of open access transportation and the restructuring of gas supply
and contractual provisions with these customers has improved the Company's
competitive position. From December 1991 through January 1992 and again from
December 1992 through May 1994, except for a brief period in June 1993,
residual fuel oil prices were lower than natural gas, but Cascade did not
experience any significant loss of sales to alternate fuels during those
periods.
In addition to multiple alternate fuels, the Company competes with other
sellers of natural gas because of the potential for bypass of the Company's
facilities. Bypass refers to actual or prospective customers which install
their own facilities and connect directly to an upstream pipeline and thereby
7
"bypass" the distribution company's service. The Company has experienced
bypass but has also experienced success in offering competitive rates to
reduce economic incentives to bypass.
The Bonneville Power Administration ( BPA ) is a major supplier of
hydro-electric power in the Pacific Northwest including Cascade's service
area. BPA significantly influences the electric rates of all classes of
customers including those applications in direct competition with natural gas
marketed by Cascade.
ENVIRONMENTAL
The Company is subject to federal and state environmental regulation of
its operations and properties through the United States Environmental
Protection Agency, the Washington Department of Ecology and the Oregon
Department of Environmental Quality. Such regulation may, at times, result
in the imposition of liability or responsibility for the clean-up or
treatment of existing environmental problems or for the prevention of future
environmental problems.
In the early 1950's, the Company purchased several of the gas
distribution facilities that it operates today. Among the acquired
facilities, the Company has identified to date twelve small manufactured gas
plants which had used oil or coal as feedstock to produce manufactured gas.
Some of the waste byproducts of the manufacturing process contain hazardous
substances which, if found in sufficient concentrations, could pose
environmental problems.
Almost all of these plants were either dismantled or converted to
propane air prior to 1956. In 1956, when natural gas became available, the
remaining plants were dismantled. The plant sites were cleaned up when the
plants were dismantled and the sites are currently being used for other
purposes. Environmental agencies have monitored three of the plant sites and
have found no hazardous substances at levels requiring remediation.
The Company has been notified of a claim regarding contamination of a
former manufactured gas site in Oregon once operated by a predecessor
company. At this date it appears that contamination is present at the site,
but there is no estimate of the extent of clean-up costs. To the extent the
Company may be responsible for any portion of such costs, it will seek
contribution from other responsible parties, recovery from its insurers and
appropriate rate relief. See Note 11 under Notes to Consolidated Financial
Statements. Based on information received to date, it is not aware of
hazardous substances present at any of the other plant sites at levels that
would require remediation.
The Company is in the process of remediating an area that was
contaminated by underground diesel and gasoline storage tanks. See Note 11
under Notes to Consolidated Financial Statements.
CAPITAL EXPENDITURES
Capital expenditures for 1996 are budgeted at $35,147,000 including
$2,300,000 of projects originally budgeted for 1995 but not completed and
carried over to 1996. Including the 1996 budget, the Company will have spent
over $168,000,000 in new plant in the five years ending in 1996 compared to
$133,252,000 in the 12-year period from 1980 through 1991. Construction of
the line to serve the
8
fifth cogeneration customer on Cascade's system was completed in February
1996. The contracts for service to the five cogeneration customers are
expected to yield relatively level payments over the 15 to 25 year contract
lives. The contracts provide for demand charges as well as distribution
charges which should recover the capital investment in the facilities and
provide a return to shareholders over their term. With level payments,
projected annual rates of return are low in the early years and increase
significantly over time as the Company's investment is depreciated.
The Company is currently forecasting that capital expenditures will
total approximately $150,000,000 over the next five years.
NON-UTILITY SUBSIDIARIES
Cascade has four non-utility subsidiaries. These subsidiaries are
engaged in the following businesses: financing Cascade customers' purchases
of energy-efficient appliances; exploring for natural gas (two subsidiaries);
and ownership of certain real property in Oregon. The subsidiaries, which in
the aggregate account for less than 5% of the consolidated assets of the
Company, do not currently have a significant impact on Cascade's financial
condition or the results of its operations.
PERSONNEL
At December 31, 1995, Cascade had 475 employees. Of the total
employees, 214 are represented by the International Chemical Workers Union.
The present contract with the union extends to April 1, 1996. As of March 22,
1996, a tentative agreement has been reached for a new contract extending to
April 1, 1999. The agreement is subject to ratification by members of Local
121 of the International Chemical Workers Union.
9
OPERATING STATISTICS
1995 1994 1993 1992 1991
Gas Distribution Revenue (thousands of dollars):
Firm:
Residential $ 56,609 $ 51,354 $ 46,456 $37,424 $37,260
Commercial 53,531 49,718 46,870 38,797 40,092
Industrial 13,320 11,959 10,931 8,715 8,343
Interruptible:
Commercial 3,589 3,705 2,954 2,927 3,068
Industrial 1,678 2,008 1,845 1,877 2,212
Non-Core 42,527 66,597 70,923 56,149 58,535
---------- ----------- ----------- ----------- ----------
Total gas sales revenue 171,254 185,341 179,979 145,889 149,510
Transportation revenue 11,300 6,871 7,087 6,423 4,658
---------- ----------- ----------- ----------- ----------
Total gas distribution revenue $182,554 $192,212 $187,066 $152,312 $154,168
---------- ----------- ----------- ----------- ----------
Gas Deliveries (thousands of therms):
Firm
Residential 91,719 88,342 87,812 71,211 71,661
Commercial 97,913 97,750 102,256 85,303 89,873
Industrial 27,726 27,214 28,208 22,585 21,984
Interruptible
Commercial 5,259 5,950 4,730 4,608 5,319
Industrial 4,000 5,459 5,925 5,944 7,350
Non-core 303,006 303,569 269,483 255,707 277,716
---------- ----------- ----------- ----------- ----------
Total Sales therms 529,623 528,284 498,414 445,358 473,903
Transportation Deliveries 424,270 377,435 240,448 159,779 84,918
---------- ----------- ----------- ----------- ----------
Total deliveries 953,893 905,719 738,862 605,137 558,821
---------- ----------- ----------- ----------- ----------
Number of Customers (average):
Firm
Residential 121,503 113,398 104,334 96,621 89,306
Commercial 22,989 22,035 21,166 20,266 19,316
Industrial 336 327 318 308 308
Interruptible
Commercial 16 18 17 17 18
Industrial 13 14 13 16 18
Non-core (including transportation) 104 91 86 80 77
---------- ----------- ----------- ----------- ----------
Total 144,961 135,883 125,934 117,308 109,043
---------- ----------- ----------- ----------- ----------
Year-end totals 151,005 142,839 132,668 123,356 114,734
---------- ----------- ----------- ----------- ----------
10
OPERATING STATISTICS (CONTINUED)
1995 1994 1993 1992 1991
Average Annual Use per Customer (therms):
Residential 755 779 842 737 802
Commercial-firm 4,259 4,436 4,831 4,209 4,653
Average Annual Revenue per Customer:
Residential $ 467 $ 453 $ 445 $ 387 $ 417
Commercial-firm $ 2,329 $ 2,256 $ 2,214 $ 1,914 $ 2,076
Average Rate per Therm:
Firm
Residential $0.6193 $0.5813 $0.5290 $0.5255 $0.5199
Commercial $0.5467 $0.5086 $0.4584 $0.4548 $0.4461
Industrial $0.4804 $0.4394 $0.3875 $0.3859 $0.3795
Interruptible
Commercial (excluding facilities charges) $0.4183 $0.3782 $0.3169 $0.3194 $0.3166
Industrial $0.4194 $0.3678 $0.3114 $0.3158 $0.3010
Non-core $0.1404 $0.2194 $0.2632 $0.2196 $0.2108
Transportation $0.0266 $0.0182 $0.0295 $0.0402 $0.0549
Average Cost per Therm of Gas Purchased $0.2246 $0.2526 $0.2434 $0.2055 $0.1958
Heating Degree Days
System average (30-year average - 5,675) 5,238 5,463 6,136 5,073 5,392
Maximum Day Send Out
(1,000 therms) including transportation 4,224 3,936 3,485 2,687 2,567
Average Daily Send Out
(1,000 therms) including transportation 2,613 2,481 2,024 1,653 1,531
Employees at End of Year 475 476 467 466 460
11
ITEM 2. PROPERTIES.
At December 31, 1995, Cascade's utility plant investments included
approximately 3,810 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 2,412 miles of service lines.
The lateral lines and distribution 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 sixteen buildings used for operations, office space and
warehousing in Washington and five such buildings in Oregon. It occupies an
additional five commercial offices and maintains 35 pay stations in
communities throughout its operating territory. 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. The Company also owns a propane air plant in Yakima, Washington,
with a capacity of 30,000 therms per day used for peak load shaving.
ITEM 3. LEGAL PROCEEDINGS.
See Item 1, Business, under "Environmental".
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
12
EXECUTIVE OFFICERS OF THE REGISTRANT
The Executive Officers of the Company, as of March 1, 1996, are as follows:
Year
Became
Name Office Age Officer
- -------------------------------------------------------------------------------
W. Brian Matsuyama Chairman of the Board and 49 1987
Chief Executive Officer
Ralph E. Boyd President and Chief 59 1988
Operating Officer
Jon T. Stoltz Senior Vice President - 49 1981
Planning and Rates
Larry E. Anderson Vice President - 47 1995
Operations
O. LeRoy Beaudry Vice President - 57 1981
Consumer and Public Affairs
King C. Oberg Vice President - 55 1993
Gas Supply
Calvin R. Steele Vice President - 56 1991
Information Technology
J. D. Wessling Vice President - Finance, and 52 1995
Chief Financial Officer
James E. Haug Treasurer and Chief 47 1981
Accounting Officer
Larry C. Rosok Corporate Secretary and 39 1995
Personnel Director
None of the above officers is related by blood, marriage or adoption
to any other of the above named officers. Except as discussed below, each of
the above named officers has been employed by the Company in a management
capacity for at least the past five years. None of the above officers hold
directorships in other public corporations. All officers serve at the
pleasure of the Board of Directors.
J. D. Wessling was employed by the Company on January 6, 1994 as
Director-Finance. From 1989 through 1993, he was chief financial officer for
a retail drug chain based in Phoenix, Arizona. From 1986 to 1989, he was
chief financial officer of a computer distribution company. Prior to that,
Mr. Wessling spent 12 years in the oil and gas industry, seven of which were
with Atlantic Richfield Company where he held various financial positions.
13
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.
1995 1994
Quarter High Low High Low
First 14-7/8 13-1/4 18-1/8 15-7/8
Second 15 13-1/2 16-3/4 14
Third 15-1/2 13-1/2 15-13/16 13-1/4
Fourth 17-3/8 14-5/8 15-1/2 12-3/4
At February 29, 1996, there were approximately 9,215 holders of the
Common Stock. The following table shows for the periods indicated the
dividends paid per share on the Common Stock.
Quarter 1995 1994
First $.24 $.23-2/3
Second $.24 $.24
Third $.24 $.24
Fourth $.24 $.24
The Company's practice has been to declare dividends on its common
shares quarterly, payable on the 15th day of February, May, August, and
November. The most recent quarterly dividend on the common shares was $.24
per share and was paid on February 15, 1996, to holders of record on January
15, 1996. Future dividend action will depend on the earnings and financial
condition of the Company and other relevant factors.
14
ITEM 6. SELECTED FINANCIAL DATA.
(dollars in thousands except per share data)
1995 1994 1993 1992 1991
STATEMENTS OF OPERATIONS:
Operating Revenues:
Gas Sales $171,254 $185,341 $179,979 $145,889 $149,510
Transportation Revenue 11,300 6,871 7,087 6,423 4,658
Other Operating Income 190 198 388 154 144
---------- ----------- ----------- ----------- ----------
182,744 192,410 187,454 152,466 154,312
Less: Gas Purchases 102,858 118,083 113,500 90,320 90,903
Revenue Taxes 11,480 11,500 11,095 8,997 9,362
---------- ----------- ----------- ----------- ----------
Operating Margin 68,406 62,827 62,859 53,149 54,047
---------- ----------- ----------- ----------- ----------
Cost of Operations:
Operating expenses 30,818 30,202 27,856 25,576 24,053
Depreciation and amortization 11,733 10,921 9,964 9,175 8,426
Property and payroll taxes 4,051 4,039 3,757 3,516 3,361
---------- ----------- ----------- ----------- ----------
46,602 45,162 41,577 38,267 35,840
---------- ----------- ----------- ----------- ----------
Overrun Penalty Income - - - - 1,305
---------- ----------- ----------- ----------- ----------
Earnings From Operations 21,804 17,665 21,282 14,882 19,512
---------- ----------- ----------- ----------- ----------
Nonoperating Expense (Income):
Interest 9,938 8,090 7,038 7,478 7,793
Interest charged to construction (394) (203) (323) (218) (156)
---------- ----------- ----------- ----------- ----------
9,544 7,887 6,715 7,260 7,637
Amortization of debt issuance expense 606 593 562 402 362
Other (586) (80) (113) (440) (344)
---------- ----------- ----------- ----------- ----------
9,564 8,400 7,164 7,222 7,655
---------- ----------- ----------- ----------- ----------
Earnings Before Income Taxes and Cumulative
Effect of change in accounting method 12,240 9,265 14,118 7,660 11,857
Income Taxes 4,508 3,505 5,224 2,817 4,206
---------- ----------- ----------- ----------- ----------
Earnings Before Cumulative Effect of Change
in Accounting Method 7,732 5,760 8,894 4,843 7,651
Cumulative effect of change in accounting method - - 209 - -
---------- ----------- ----------- ----------- ----------
Earnings Before Preferred Dividends 7,732 5,760 9,103 4,843 7,651
Preferred Dividends 539 558 580 595 148
---------- ----------- ----------- ----------- ----------
Net Earnings $ 7,193 $ 5,202 $ 8,523 $ 4,248 $ 7,503
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
Common Stock Outstanding (thousands of shares):
End of year 9,144 8,912 8,566 7,614 6,631
Average 8,997 8,707 7,915 6,681 6,587
Earnings per Common Share
Before cumulative effect of change
in accounting method $ 0.80 $ 0.60 $ 1.05 $ 0.64 $1.14
Cumulative effect of change
in accounting method - - 0.03 - -
---------- ----------- ----------- ----------- ----------
Net Earnings per Common Share $ 0.80 $ 0.60 $ 1.08 $ 0.64 $1.14
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
15
ITEM 6. SELECTED FINANCIAL DATA (CONTINUED)
(dollars in thousands except per share data)
1995 1994 1993 1992 1991
RETAINED EARNINGS:
Beginning of the year $ 10,806 $ 14,076 $ 13,455 $ 15,655 $ 14,142
Net earnings after preferred dividends 7,193 5,202 8,523 4,248 7,503
Common dividends (8,702) (8,472) (7,902) (6,448) (5,990)
---------- ----------- ----------- ----------- ----------
End of the year $ 9,297 $ 10,806 $ 14,076 $ 13,455 $ 15,655
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
CAPITAL STRUCTURES:
Common shareholders' equity $ 89,539 $ 87,710 $ 85,702 $ 69,199 $ 57,225
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
Redeemable preferred stocks $ 6,851 $ 7,217 $ 7,528 $ 7,951 $ 8,254
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
Debt:
Long-term debt $102,100 $100,000 $ 87,000 $ 74,677 $ 57,060
Notes Payable 32,000 14,501 13,502 13,000 8,500
Current maturities of long-term debt - 5,000 - - 3,500
---------- ----------- ----------- ----------- ----------
$134,100 $119,501 $100,502 $ 87,677 $ 69,060
---------- ----------- ----------- ----------- ----------
Total capital $230,490 $214,428 $193,732 $164,827 $134,539
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
FINANCIAL RATIOS:
Return on common shareholders' equity 8.12% 6.00% 11.00% 6.72% 13.38%
Common stock dividend payout ratio 120% 161% 87% 146% 79%
Dividends paid in cash per common share $ 0.96 $ 0.96 $ 0.94 $ 0.93 $ 0.90
Fixed charge coverage (before income tax
deduction):
Times interest earned 2.16 2.07 2.86 1.97 2.45
Times interest and preferred dividends
earned 2.00 1.87 2.55 1.76 2.39
Book value per year-end share of common stock $ 9.79 $ 9.84 $ 10.00 $ 9.09 $ 8.63
UTILITY PLANT:
Utility plant - end of year $362,924 $333,863 $315,297 $283,871 $249,027
Accumulated depreciation 138,831 127,806 117,925 109,184 100,927
---------- ----------- ----------- ----------- ----------
Net plant $224,093 $206,057 $197,372 $174,687 $148,100
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
Construction expenditures $ 37,637 $ 27,251 $ 32,990 $ 35,335 $ 19,669
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
Total assets $296,898 $273,090 $252,690 $224,685 $191,471
---------- ----------- ----------- ----------- ----------
---------- ----------- ----------- ----------- ----------
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION.
The following is management's assessment of the Company's financial
condition and a discussion of the principal factors that affect consolidated
results of operations for the years 1995, 1994 and 1993.
EARNINGS AND DIVIDENDS
Per share results for 1995 were up 33% over 1994, despite the negative
impact of warm weather on residential and commercial consumption. Warm
weather during the heating season negatively impacted net earnings by an
estimated $0.21 per share.
EARNINGS AND DIVIDENDS
(in thousands except per share data)
- ------------------------------------------------------------------
1995 1994 1993
Net Income $7,193 $5,202 $8,523
Net Income per Share 0.80 $ 0.60 $ 1.08
Dividends per Share 0.96 $ 0.96 $ 0.94
Average Shares Outstanding 8,997 8,707 7,915
- ------------------------------------------------------------------
Per share net earnings for 1994 were reduced by non-recurring costs of
$0.13 for interstate pipeline capacity to serve Oregon customers and $0.05
for revaluation of certain non-operating assets. Warmer than normal
temperatures also affected the comparison to 1993, when temperatures were
colder than normal. The warmer than normal temperatures impacted per share
net earnings by an estimated $0.15.
RESIDENTIAL AND COMMERCIAL OPERATING MARGIN
RESIDENTIAL AND COMMERCIAL OPERATING MARGIN
(dollars in thousands)
- -------------------------------------------------------------------------
1995 1994 1993
Degree Days 5,238 5,463 6,136
Average Customers
Residential 121,503 113,398 104,334
Commercial 22,989 22,035 21,166
Consumption per Customer
Residential 755 779 842
Commercial 4,259 4,436 4,831
Margin
Residential $23,422 $21,730 $22,056
Commercial $18,162 $16,795 $18,437
- -------------------------------------------------------------------------
The average number of residential and commercial customers increased
by 9,059 in 1995 which contributed approximately $2 million of additional
operating margin. The rate of customer growth is down from the 1994 increase
of 9,933, due primarily to a general slow down of economic activity in much
of the service area.
Consumption per customer for 1995 was down 3% for residential and 4%
for commercial from 1994. The reductions were directly attributable to
weather, 15% warmer than normal in November, and 4% warmer than normal in
December. The weather resulted in declines of 11% for residential consumption
and
17
13% for commercial consumption in the key fourth quarter heating months.
Eliminating the effects of weather, estimated consumption per customer for
the year would have been approximately 810 therms for residential and 4,500
therms for commercial. Normalized residential consumption levels remain
consistent over the last three years because additional natural gas
equipment, such as water heaters converted from electricity are offsetting
the effects of more energy efficient buildings and appliances.
NON-CORE INDUSTRIAL
Non-core industrial operating margin was $21.5 million in 1995, an
increase of $2.0 million, or 10%. The 1995 increase is attributable to the
start up in June 1995 of a new cogeneration plant at an existing customer
site and increased throughput to a broad spectrum of industrial customers.
Operating margins in 1994 increased $2.4 million over 1993 primarily as a
result of service to a new cogeneration customer beginning in April 1994. A
fifth cogeneration plant is expected to begin receiving distribution service
from Cascade in the first quarter of 1996.
OPERATING EXPENSES
Operating expenses, almost 70% of which are payroll and benefits
costs, increased over 1994 by $616,000, or 2%. The increase is due primarily
to a December 31, 1994 enhancement in retirement plan benefits to bring
benefits up to industry norm. There was also an increase in lease expense
reflecting the use of operating leases beginning in 1995 for certain vehicles
formerly purchased. Mitigating the expense increase was the Company's ability
to maintain a stable number of employees in the face of strong, continuing
customer growth. Another moderating factor was the increase in payroll
capitalized due to increased capital expenditures.
Operating expenses in
1994 were up over 1993 by 8.4%. Payroll and benefits costs account for 65% of
this increase, with the largest factor being additional payroll cost of
$912,000. This upward movement is the result of general salary and wage
increases, the addition of 9 employees as of the end of the year, and a
reduction in payroll expense capitalized resulting from lower capital
expenditures in 1994. Employee medical benefits expense increased 26.1% over
1993 due to adverse claims experience.
DEPRECIATION AND AMORTIZATION, PROPERTY AND PAYROLL TAXES
Depreciation and amortization were up 7.4% in 1995 over 1994. The
increase is due to higher depreciable plant consistent with an 8.7% increase
in utility plant. Property and payroll taxes were essentially unchanged from
1994 due to a reduction in property tax rates stemming from a voter mandated
1990 reduction in Oregon. This reduction in property taxes is reflected in
Oregon rates. Depreciation and amortization expense in 1994, along with
property and payroll taxes, were up over 1993 a total of $1.2 million, or
9.0%, primarily because of increases in plant and equipment.
INTEREST EXPENSE AND OTHER
Interest expense in 1995 was $1.8 million, or 22.8% higher than 1994.
Of this increase, $1.1 million is due to $18 million of additional long-term
debt issued in October 1994. The remainder of the increase is due to interest
on credits for lower gas costs deferred for pass-back to customers,
discontinuance of interest rate swaps amortized over the term of the
underlying debt agreement, and interest on customer deposits.
Interest expense for 1994 increased $1.2 million over 1993 due to an
increase of $16.7 million in the amount of debt outstanding. Other expense
for 1994 includes charges of $700,000 for revaluation of certain non
operating assets.
18
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
entered into a new 5 year credit agreement on September 22, 1995, for a
commitment of $40 million from three banks which replaces two separate
commitments that totaled $25 million. The committed lines also support a
money market facility of a similar amount. A subsidiary has a $5 million
revolving credit facility used for non regulated business, which expires in
2000, and at December 31, 1995, $2.1 million was outstanding under the
facility. The Company also has $25 million of uncommitted lines from three
banks.
The Company has a Medium-Term Note program used for long-term financing
with $100 million outstanding at December 31, 1995, and $50 million
registered under the Securities Act of 1933 and available for issuance.
Because of the availability of short-term credit and the ability to issue
long-term debt and additional equity, management is of the opinion it has
adequate financial flexibility to meet its anticipated cash needs.
CAPITAL EXPENDITURES
Capital Expenditures
- ---------------------
(dollars in thousands)
- -----------------------------------------------------------
- -----------------------------------------------------------
1995 1994 1993
Capital Expenditures $37,637 $27,251 $32,990
------- ------- -------
Operating Cash Flow $25,023 $12,851 $13,960
Dividends Paid (8,200) (8,154) (7,506)
Redemption of Preferred (362) (309) (455)
------- ------- -------
Available Cash Flow $16,461 $ 4,388 $ 5,999
------- ------- -------
Internally Funded Expenditures 43.74% 16.10% 18.18%
- -----------------------------------------------------------
- -----------------------------------------------------------
Available cash flow increased in 1995, primarily due to increased net
earnings, lower gas costs and a reduction in accounts receivable to a level
approximating 1993. These lower gas costs will be refunded to customers
beginning in 1996. Budgeted expenditures for 1996 will approximate $35.2
million and will be financed 30% to 40% from operating cash flow net of
common and preferred dividends. Over the next five years it is expected that
capital expenditures will be close to $150 million.
In addition to internally generated cash, the Company's cash flow is
enhanced from monthly sales of Common stock to participants of the Dividend
Reinvestment Plan and employees in the Company's 401(k) Plan. Cash in-flow
from these sources was $2.3 million in 1995, $4.4 million in 1994 and
$589,000 in 1993. The significant increase from 1993 to 1994 reflects opening
the Dividend Reinvestment Plan in 1994 to customers wishing to invest in
Cascade stock.
Financing plans for 1996 include the possible private placement of $7.5
million of preferred stock in the first half of the year and issuance of 1 to
1.5 million common shares later in the year. Proceeds from these financings
will be used to retire short-term debt and for other general corporate
purposes. The method, timing and amount of these and any future financings by
the Company will depend on a variety of factors, including capitalization
ratios, coverage ratios, interest costs, the state of the capital markets and
general economic conditions.
EFFECTS OF INFLATION
Changing prices have had minimal impact on the Company's operating
margins in the last three years. The effects of price changes in purchased
gas costs and the cost of transporting gas to the Company's system are, for
the most part, passed on to customers in accordance with regulatory policy.
Inflationary increases in wages and other operating expenses are generally
recognized by the regulatory agencies in their rate decisions in general rate
filings.
19
REGULATORY MATTERS
Since June 1995, the Company has engaged in a negotiation process with
the staff of the WUTC and other interested parties, to establish new rates
for Washington customers. On December 11, 1995 Cascade filed a formal
request for a general rate increase, incorporating the results of agreements
reached to date with the staff. Negotiations continue regarding remaining
revenue level, rate spread and rate design issues. Under normal weather
conditions, the annual revenue increase from the requested rates, if granted
in full, would be $5.7 million, a 3.45% increase. Also included in the
filing proposal are changes to the design of residential and commercial
rates which would increase monthly service charges and per therm commodity
rates for the first fifty therms of gas used each month, and decrease
commodity rates for use in excess of fifty therms. The higher monthly service
charge would be applied to residential customers during winter months only.
Commercial customers would experience a higher service charge throughout the
year. This rate structure would, if approved by the WUTC, minimize the
impact of cyclical weather on bills, and would reduce financial hardship
experienced by residential and commercial customers as the result of
extremely cold weather.
On December 29, 1995 Cascade filed two additional applications with the
WUTC to lower rates to customers. The first request, which passes through to
customers reductions in the Company's costs of purchased gas, is estimated
to reduce annual revenues by $5.9 million or 3.8%. The second application
requests a pass through to customers, over a two year period, of $6.6 million
in gas cost savings and other deferred balances. It is estimated that this
application will reduce annual revenues by $3.4 million, or 2.2%. On January
26, 1996, the Company withdrew both applications in order to allow time to
work with the WUTC staff on its review of the filings. It is the Company's
intent to re-file the applications after any questions raised by the staff
are satisfied, with a desire to have these filings go into effect at the
same time as the general rate increase. It is not known when the rate changes
will be approved by the WUTC.
Effective December 1, 1995, the OPUC approved an order allowing Cascade
to decrease rates approximately $1.6 million or 5%. About $1.2 million of
this decrease is associated with current purchased gas costs applicable to
Oregon. The remainder of the decrease relates to the amortization of
conventional deferred revenue and gas cost amounts.
ENVIRONMENTAL
The Company has provided approximately $500,000 for cleanup costs
associated with contamination in the area of the Company's underground
storage tanks at its Sunnyside, Washington office. It is expected that any
additional costs will not be significant.
The Company has been notified of a claim regarding contamination of a
former manufactured gas site in Oregon once operated by a predecessor
company. At this date it appears that contamination is present at the site,
but there is no estimate of the extent of clean-up costs. To the extent the
Company may be responsible for any portion of such costs, it will seek
contribution from other responsible parties, recovery from its insurers and
appropriate rate relief. See Note 11 under Notes to Consolidated Financial
Statements.
20
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS REPORT
Board of Directors
Cascade Natural Gas Corporation
Seattle, Washington
We have audited the accompanying consolidated balance sheets of Cascade
Natural Gas Corporation and subsidiaries (the Corporation) as of December 31,
1995 and 1994, and the related consolidated statements of net earnings,
common shareholders' equity, and cash flows for each of the three years in
the period ended December 31, 1995. These financial statements are the
responsibility of the Corporation's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial 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 December 31, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1995, in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Seattle, Washington
February 5, 1996
21
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF NET EARNINGS
YEARS ENDED DECEMBER 31
1995 1994 1993
(THOUSANDS EXCEPT PER SHARE DATA)
OPERATING REVENUES:
Gas sales $171,254 $185,341 $179,979
Transportation revenue 11,300 6,871 7,087
Other operating income 190 198 388
-------- -------- --------
182,744 192,410 187,454
Less:
Gas purchases 102,858 118,083 113,500
Revenue taxes 11,480 11,500 11,095
-------- -------- --------
OPERATING MARGIN 68,406 62,827 62,859
-------- -------- --------
COST OF OPERATIONS:
Operating expenses 30,818 30,202 27,856
Depreciation and amortization 11,733 10,921 9,964
Property and payroll taxes 4,051 4,039 3,757
-------- -------- --------
46,602 45,162 41,577
-------- -------- --------
Earnings from operations 21,804 17,665 21,282
-------- -------- --------
NONOPERATING EXPENSE (INCOME):
Interest 9,938 8,090 7,038
Interest charged to construction (394) (203) (323)
-------- -------- --------
9,544 7,887 6,715
Amortization of debt issuance expense 606 593 562
Other (586) (80) (113)
-------- -------- --------
9,564 8,400 7,164
-------- -------- --------
EARNINGS BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING METHOD 12,240 9,265 14,118
INCOME TAXES 4,508 3,505 5,224
-------- -------- --------
EARNINGS BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING METHOD 7,732 5,760 8,894
Cumulative effect of change in
accounting method (Note 8) - - 209
-------- -------- --------
EARNINGS BEFORE PREFERRED DIVIDENDS 7,732 5,760 9,103
PREFERRED DIVIDENDS 539 558 580
-------- -------- --------
NET EARNINGS $7,193 $5,202 $8,523
-------- -------- --------
-------- -------- --------
EARNINGS PER COMMON SHARE:
Before cumulative effect of change
in accounting method $0.80 $0.60 $1.05
Cumulative effect of change in
accounting method - - 0.03
-------- -------- --------
NET EARNINGS PER COMMON SHARE $0.80 $0.60 $1.08
-------- -------- --------
-------- -------- --------
AVERAGE SHARES OUTSTANDING (NOTE 5) 8,997 8,707 7,915
-------- -------- --------
-------- -------- --------
See notes to consolidated financial statements
22
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31
1995 1994
(DOLLARS IN THOUSANDS)
UTILITY PLANT (Note 3) $362,924 $333,863
Less Accumulated depreciation 138,831 127,806
--------- ---------
224,093 206,057
Construction work in progress 14,957 7,872
--------- ---------
239,050 213,929
--------- ---------
OTHER ASSETS:
Investments 919 919
Notes receivable, less current
maturities 2,426 2,915
--------- ---------
3,345 3,834
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents 2,197 3,949
Securities available for sale - 1,466
Accounts receivable, less allowance
of $425 and $461 for doubtful
accounts 26,483 28,885
Current maturities of notes receivable 809 988
Materials, supplies, and inventories 6,047 5,583
Prepaid expenses and other assets 2,353 1,653
--------- ---------
37,889 42,524
--------- ---------
DEFERRED CHARGES 16,614 12,803
--------- ---------
$296,898 $273,090
--------- ---------
--------- ---------
See notes to consolidated financial statements
23
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
COMMON SHAREHOLDERS' EQUITY,
PREFERRED STOCKS AND LIABILITIES
DECEMBER 31
1995 1994
(DOLLARS IN THOUSANDS)
COMMON SHAREHOLDERS' EQUITY
Common stock, par value $1 per share (Note 5)
Authorized, 15,000,000 shares; issued
and outstanding, 9,144,448 and 8,911,661
shares $ 9,144 $ 8,912
Additional paid-in capital 71,098 67,992
Retained earnings (Note 7) 9,297 10,806
--------- ---------
89,539 87,710
--------- ---------
REDEEMABLE PREFERRED STOCKS, aggregate
redemption amount of $7,103 and
$7,499 (Note 4) 6,851 7,217
--------- ---------
LONG-TERM DEBT (Note 7) 102,100 100,000
--------- ---------
CURRENT LIABILITIES:
Notes Payable (Note 6) 32,000 14,501
Accounts payable 16,392 18,366
Property, payroll, and excise taxes 4,578 4,541
Dividends and interest payable 4,365 4,202
Other current liabilities 4,646 1,620
Current maturities of long-term debt (Note 7) - 5,000
--------- ---------
61,981 48,230
--------- ---------
DEFERRED CREDITS:
Gas cost changes 10,934 5,200
Income taxes (Note 8) 16,461 15,382
Investment tax credits 3,207 3,472
Other 5,825 5,879
--------- ---------
36,427 29,933
--------- ---------
COMMITMENTS & CONTINGENCIES (Note 10 and 11) - -
--------- ---------
$296,898 $273,090
--------- ---------
--------- ---------
See notes to consolidated financial statements
24
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
COMMON STOCK
PAR ADDITIONAL PAID RETAINED
SHARES VALUE IN CAPITAL EARNINGS
(DOLLARS IN THOUSANDS)
BALANCE, JANUARY 1, 1993 5,075,726 $ 5,076 $50,668 $ 13,455
Common stock issued:
Public offering 575,000 575 13,773
Employee savings plan and
retirement trust (401(k)) 22,200 22 558
Director stock award plan 800 1 19
Dividend reinvestment plan 37,992 38 939
Three-for-two stock split 2,854,656 2,854 (2,865)
Redemption of preferred stock (32)
Cash dividends:
Common stock, $.94 per share (7,902)
Preferred stock, senior,
$.55 per share (109)
7.85% cumulative preferred
stock $7.85 per share (471)
Earnings before preferred
dividends 9,103
--------- ------- ------- --------
BALANCE, DECEMBER 31, 1993 8,566,374 8,566 63,060 14,076
Common stock issued:
Employee savings plan and
retirement trust (401(k)) 48,959 49 690
Director stock award plan 1,200 1 18
Dividend reinvestment plan 295,128 296 4,222
Redemption of preferred stock 2
Cash dividends:
Common stock, $.96 per share (8,472)
Preferred stock, senior, $.55
per share (87)
7.85% cumulative preferred
stock, $7.85 per share (471)
Earnings before preferred
dividends 5,760
--------- ------- ------- --------
BALANCE, DECEMBER 31, 1994 8,911,661 $ 8,912 $67,992 $ 10,806
Common stock issued:
Employee savings plan and
retirement trust (401(k)) 50,373 50 677
Director stock award plan 1,200 1 15
Dividend reinvestment plan 181,214 181 2,409
Redemption of preferred stock 5
Cash dividends:
Common stock, $.96 per share (8,702)
Preferred stock, senior,
$.55 per share (68)
7.85% cumulative preferred
stock, $7.85 per share (471)
Earnings before preferred
dividends 7,732
--------- ------- ------- --------
BALANCE, DECEMBER 31, 1995 9,144,448 $ 9,144 $71,098 $ 9,297
--------- ------- ------- --------
--------- ------- ------- --------
See notes to consolidated financial statements
25
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
1995 1994 1993
(DOLLARS IN THOUSANDS)
OPERATING ACTIVITIES:
Earnings before preferred dividends $ 7,732 $ 5,760 $ 9,103
Adjustments to reconcile earnings
before preferred dividends to net
cash provided by operating
activities:
Depreciation 12,131 11,239 10,268
Write-down of assets - 700 349
Amortization of gas cost changes 3,508 (3,361) (10,119)
Increase in deferred income taxes 1,079 1,674 758
Cumulative effect of change in
accounting method - (209)
Decrease in deferred investment tax
credits (265) (275) (266)
Cash provided (used) by changes in
operating assets and liabilities:
Accounts receivable 2,400 (2,346) (2,099)
Income taxes 105 (476) 98
Inventories 201 34 (601)
Gas cost changes 2,226 4,993 (482)
Deferred items (4,144) (662) 490
Accounts payable and accrued
expenses 1,560 (3,661) 6,563
Prepaid expenses and other assets (1,111) (725) 138
Other (399) (43) (31)
------- -------- -------
Net cash provided by operating
activities 25,023 12,851 13,960
------- -------- -------
INVESTING ACTIVITIES:
Capital expenditures (37,637) (27,251) (32,990)
New consumer loans (1,243) (1,393) (2,352)
Receipts on consumer loans 2,277 2,580 3,533
Purchase of securities available
for sale (4,107) (1,502) (747)
Proceeds from securities available
for sale 5,605 752 -
------- -------- -------
Net cash used by investing activities (35,105) (26,814) (32,556)
------- -------- -------
FINANCING ACTIVITIES:
Issuance of common stock 2,293 4,400 14,937
Redemption of preferred stock (362) (309) (455)
Proceeds from long-term debt 2,100 17,838 33,686
Repayment of long-term debt (5,000) - (22,761)
Proceeds from notes payable, net 17,499 999 501
Dividends paid (8,200) (8,154) (7,506)
------- -------- -------
Net cash provided by financing
activities 8,330 14,774 18,402
------- -------- -------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (1,752) 811 (194)
CASH AND CASH EQUIVALENTS:
Beginning of year 3,949 3,138 3,332
------- -------- -------
End of year $ 2,197 $ 3,949 $ 3,138
------- -------- -------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amounts
capitalized) $ 8,597 $ 7,381 $ 6,744
Income taxes $ 2,786 $ 2,567 $ 2,598
SUPPLEMENTAL DISCLOSURE OF NONCASH
INVESTING ACTIVITIES:
In July, 1994 the Company sold all of the capital stock of Metrology One, Inc. and
Fibre Graphics, Inc. A note receivable valued at $825,000 was acquired in exchange for
the assets sold. As of December 31, 1995, the note is included in Notes Receivable at a
net value of $269,000.
See notes to consolidated financial statements
26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF BUSINESS
Cascade Natural Gas Corporation (the Company) is a local distribution
company (LDC) engaged in the distribution of natural gas. The Company's
service territory consists primarily of small towns in Washington and Oregon,
ranging from the Canadian border in northwestern Washington to the Idaho
border in eastern Oregon. The Company also has four immaterial subsidiaries.
As of December 31, 1995, the Company had approximately 151,000 core
customers and 116 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 24% of gas deliveries and 69% of
operating margin. The Company's sales to its core residential and commercial
customers are vulnerable to weather fluctuations. The results of operations
for any one year may be significantly affected by variations in the weather.
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 distribution service on the Company's system. The Company's
margin from non-core customers is derived only from this distribution
service. The principal industrial activities of its customers include the
processing of forest products, production of chemicals, refining of crude
oil, production of aluminum, generation of electricity, and processing of
food.
The Company is subject to regulation of most aspects of its operations
by the Washington Utilities and Transportation Commission (WUTC) and the
Oregon Public Utility Commission (OPUC). It is subject to regulatory risk
primarily with respect to recovery of costs incurred. Various deferred
charges and deferred credits reflect assumptions regarding recovery of
certain costs through amortization during future periods.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company's accounting records and practices conform to the requirements
and uniform system of accounts prescribed by the WUTC and the OPUC.
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. These costs include payroll-related costs such as taxes and other
employee benefits, general and administrative costs, and the estimated cost of
funds used during construction. Maintenance and repairs of property, and
replacements and renewals of items deemed to be less than units of property, are
charged to operations. Units of utility plant retired or replaced are credited
to property accounts at cost. Such amounts plus removal expense, less salvage,
are charged to accumulated depreciation. In the case of a sale of land 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.
The asset lives used for computing depreciation range from five to forty years,
and the weighted average annual depreciation rate is approximately 3.5%.
INVESTMENTS: Investments consist primarily of real estate, classified as
nonutility property carried at estimated net realizable value.
NOTES RECEIVABLE: Notes receivable include loans made to customers for the
purchase of energy efficient appliances, which are generally the security for
the loan. Loans are made for a term of five years at interest rates varying
from 6.5% to 12%.
SECURITIES AVAILABLE FOR SALE: Securities available for sale consist of
municipal bonds, at market value, which approximates cost.
MATERIALS, SUPPLIES AND INVENTORIES: Materials and supplies for
construction and maintenance are recorded at cost. Inventories of gas are
stated at the lower of average cost or market.
DEFERRED CHARGES: Deferred charges consist primarily of debt issuance
costs, intangible assets related to minimum liability accruals on pension
obligations (Note 9), and deferrals of postretirement health care expenses (Note
9). Debt issuance costs are amortized over the lives of the related issues.
Redemption costs relating to refinanced debt are amortized over the life of the
new debt issuance.
REVENUE RECOGNITION: The Company accrues estimated revenues for gas
delivered but not billed to residential and commercial customers from the meter
reading dates to month end.
GAS COST CHANGES: Gas cost changes consist primarily of the effects of
net decreases in purchased gas costs which have not yet been reflected in rates
charged to customers. The effects of changes that are not tracked on a
concurrent basis are deferred and amortized over a future period through a
temporary rate change schedule. Amortization is subject to approval by the
regulatory agencies, and amortization periods are generally one to two years.
FEDERAL INCOME TAXES: The Company deducts depreciation computed on an
accelerated basis for federal income tax purposes, and as a result, deductions
exceed the amounts included in the financial statements.
In 1981, the Company elected to record depreciation on 1981 and subsequent
utility plant additions under the Accelerated Cost Recovery System. This
election required the Company to provide deferred income taxes on the difference
between depreciation computed for financial statement and tax reporting purposes
beginning in 1981 (Note 8). This procedure has been accepted by the WUTC and
the OPUC.
It is expected that any future increases in federal income taxes resulting
from the reversal of accelerated depreciation on additions to utility plant in
1980 and prior will be allowed in future rate determinations.
INVESTMENT TAX CREDITS: Investment tax credits were deferred and are
amortized over the life of the property giving rise to the credit.
STATEMENTS OF CASH FLOWS: For purposes of the statements of cash flows,
the Company considers all liquid investments with a purchased maturity of
approximately three months or less to be cash equivalents.
RECLASSIFICATIONS: Certain reclassifications have been made in the 1994
and 1993 financial statements to conform to the classifications used in 1995.
USE OF ESTIMATES: The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.
The Company has used significant estimates in measuring certain deferred
charges and deferred credits related to items subject to approval of the WUTC
and the OPUC. Significant estimates are also used in the development of
discount rates and trend rates related to the measurement of retirement
benefit obligations and accrual amounts, and in the determination of
depreciable lives of utility plant.
NOTE 3 - UTILITY PLANT
Utility plant consists of the following components at December 31:
1995 1994
(dollars in thousands)
Distribution plant $ 311,624 $ 284,305
Transmission plant 14,086 14,086
Production plant 1,053 1,053
General plant 30,622 28,994
Intangible plant 212 212
Nondepreciable plant 5,327 5,213
----------- ----------
$ 362,924 $ 333,863
----------- ----------
----------- ----------
Note 4 - Redeemable Preferred Stocks
1995 1994 1993
Shares Amount Shares Amount Shares Amount
(dollars in thousands)
7.85% cumulative, $1.00 par value 60,000 $ 6,000 60,000 $ 6,000 60,000 $ 6,000
$.55 cumulative senior, series A,B,
and C, without par value:
Beginning of year 135,427 1,217 167,676 1,528 213,157 1,951
Retirements 38,867 366 32,249 311 45,481 423
------- ------ ------- ------- ------- -------
Authorized, issued, and outstanding
at end of year 156,560 $ 6,851 195,427 $ 7,217 227,676 $ 7,528
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Senior preferred stock is subject to mandatory redemption as follows:
Shares Amount
(dollars in thousands)
1996 24,810 $ 248
1997 25,000 $ 250
1998 25,000 $ 250
1999 14,500 $ 145
2000 7,250 $ 73
The shares may be purchased on the open market, or redeemed at
$10 per share plus accrued dividends. Redemption in excess of the required
number of shares of preferred stock can be made only if all cumulative
dividends on preferred stock have been paid. The 7.85% cumulative preferred
stock may not be redeemed until maturity on November 1, 1999.
Note 5 - Common Stock
At December 31, 1995, shares of common stock are reserved for issuance
as follows:
Number Purchase or Contribution Price
of shares Per Share
Employee Savings Plan and
Retirement Trust (401(k) plan) 230,944 Market closing price of common
stock immediately prior to
purchase by the trustee.
Divident reinvestment plan 347,619 Average of high and low sales
prices on the closest
business day immediately
preceding the investment
date, which is the 15th day
of each month.
Director stock award plan 9,600 Market closing price of common
stock on the day of the
Company's annual meeteing.
-------
588,163
-------
-------
Effective December 20, 1993, the Company issued 2,854,656 shares of
common stock in a three-for-two stock split. For the calculations of
earnings per share of common stock, the average number of shares outstanding
has been recalculated to reflect the effect of this split.
Note 6 - Notes Payable
The Company's short-term borrowing needs are met with a $40,000,000 five
year revolving credit agreement with three of its banks for an annual
commitment fee of 1/8 of 1%. The committed lines of credit also support a
commercial paper facility of a similar amount. The Company also has
$25,000,000 of uncommitted lines from three banks. A subsidiary company has
a $5,000,000 revolving credit facility used for non-regulated business, and
at December 31, 1995, $2,100,000 was outstanding for a fixed term of five
years. Of the $32,000,000 in short term borrowing outstanding at December
31, $27,000,000 was from committed lines, and $5,000,000 was from
uncommitted lines.
1995 1994 1993
(dollars in thousands)
Amount outstanding at December 31 $32,000 $ 14,501 $ 13,502
Average daily balance outstanding 13,170 15,217 11,696
Average interest rate, excluding
commitment fee 6.29% 4.87% 3.66%
Maximum month end amount outstanding 32,000 23,941 22,752
Note 7 - Long-term Debt
Long-term debt consists of the following:
1995 1994
(dollars in thousands)
9.46% Promissory note due 1995 $ - $ 5,000
6.53% Five Year Term Note 2,100 -
due 2000
Medium-term notes:
5.77% due 1998 5,000 5,000
5.78% due 1998 5,000 5,000
7.18% due 2004 4,000 4,000
7.32% due 2004 22,000 22,000
8.38% due 2005 5,000 5,000
8.35% due 2005 5,000 5,000
8.50% due 2006 8,000 8,000
8.06% due 2012 14,000 14,000
8.10% due 2012 5,000 5,000
8.11% due 2012 3,000 3,000
7.95% due 2013 4,000 4,000
8.01% due 2013 10,000 10,000
7.95% due 2013 10,000 10,000
--------- ---------
102,100 105,000
Less current maturities - 5,000
--------- ---------
$ 102,100 $ 100,000
--------- ---------
--------- ---------
None of the long-term debt includes sinking fund requirements. 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 $18,385,000 is available for payment
of dividends as of December 31, 1995.
During 1992 and 1994, the Company entered into three interest rate swap
arrangements, with scheduled expiration dates in 1994, 1995 and 1996. These
arrangements effectively converted $25,000,000 of fixed rate debt instruments
into variable rate obligations. Under the terms of these arrangements, the
Company made payments at a LIBOR-based floating rate, and received payments
at a fixed rate. The net interest paid or received is included in interest
expense. During 1994, these arrangements were terminated. The settlement
amount, which was not material, was charged to prepaid expenses, and is being
amortized to interest expense over the original terms of the swap
arrangements.
Note 8 - Income Taxes
The Company adopted Statement of Financial Accounting Standards (SFAS)
No. 109, "Accounting for Income Taxes", effective January 1, 1993. This
statement supersedes Accounting Principles Board (APB) Opinion No. 11 and
SFAS No. 96, the latter of which was never adopted by the Company. The
cumulative effect of adopting SFAS No. 109 on the Company's financial
statements was to increase net earnings by $209,000 ($.03 per share) in the
first quarter of 1993.
Under the provisions of SFAS No. 109, the Company was required to record 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 was required to adjust 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 had no effect on net earnings. The provision for
income tax expense consists of the following:
1995 1994 1993
(dollars in thousands)
Current tax expense $ 2,661 $ 2,120 $ 3,443
Alternative minimum tax
(credit carryforward) - - (665)
Deferred tax expense 2,112 1,660 2,668
Change in tax rates - - 44
Amortization of deferred
investment tax credits (265) (275) (266)
-------- --------- ---------
$ 4,508 $ 3,505 $ 5,224
-------- --------- ---------
-------- --------- ---------
During the third quarter of 1993, the Revenue Reconciliation Act of 1993
was enacted. This act increased the maximum federal income tax rate
applicable to corporations from 34% to 35%. The provision for deferred
income taxes included a charge of $44,000 ($.01 per share) in 1993 as a
result of recalculating certain deferred tax balances at the new tax rate. A
reconciliation between income taxes calculated at the statutory federal tax
rate and income taxes reflected in the financial statements is as follows:
1995 1994 1993
(dollars in thousands)
Statutory federal income tax rate 35% 35% 35%
Income tax calculated at statutory federal rate $ 4,284 $ 3,243 $ 4,941
Increase (decrease) resulting from:
State income tax, net of federal tax benefit 86 80 106
Differences between book and tax depreciation 339 468 441
Amortization of investment tax credits (265) (275) (266)
Other 64 (11) 2
-------- --------- --------
$ 4,508 $ 3,505 $ 5,224
-------- -------- --------
-------- -------- --------
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 are as follows:
1995 1994
(dollars in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $ 13,910 $ 13,082
Debt refinancing costs 2,315 2,505
Retirement benefit obligations 1,359 829
Other 1 77
--------- ---------
17,585 16,493
--------- ---------
--------- ---------
Deferred tax assets:
Valuation reserves 313 264
Retirement benefit obligations 434 477
Provision for doubtful accounts 173 172
Other 204 198
--------- ---------
1,124 1,111
--------- ---------
Net deferred tax liability $ 16,461 $ 15,382
--------- ---------
--------- ---------
Note 9 - Retirement Plans
The Company's noncontributory defined benefit pension plan covers
substantially all employees over 21 years of age with one year of service.
The benefits are based on a formula which includes credited years of service
and the employee's annual compensation. The Company's policy is generally to
fund the plan to the extent allowable under Internal Revenue Service rules.
The Company provides executive officers with supplemental retirement,
death, and disability benefits. Under the plan, vesting occurs on the first
day of the year after the executive has reached age 55 and has completed five
years of participation under the plan, or upon death. The plan supplements
the benefit received through Social Security and the defined benefit pension
plan so that the total retirement benefits equal 70% of the executive's
highest salary during any of the five years preceding retirement. The plan
also provides a death benefit equivalent to ten years of vested benefits.
The Company funds the plan by making contributions to the Trust sufficient to
assure assets held by the Trust always exceed the accumulated benefit
obligation for benefits payable by the plan.
The funded status of the defined benefit pension and supplemental
retirement plans and amounts recognized in the Company's financial
statements are shown below:
Supplemental Retirement
Pension Plan Plan
1995 1994 1995 1994
(dollars in thousands)
Actuarial present value of accumulated
benefit obligations:
Vested $ 21,863 $ 12,666 $ 3,141 $ 2,310
Nonvested 195 137 199 144
--------- --------- -------- --------
$ 22,058 $ 12,803 $ 3,340 $ 2,454
--------- --------- -------- --------
--------- --------- -------- --------
Projected benefit obligation for services
rendered to date $ (26,618) $ (15,590) $ (3,813) $ (3,327)
Plan assets, at fair value, primarily common stocks,
corporate bonds, and life insurance policies 19,376 13,842 3,430 2,387
--------- --------- -------- --------
Projected benefit obligation in excess of
plan assets (7,242) (1,748) (383) (940)
Unrecognized amounts:
Prior service cost 3,754 2,316 (284) -
Loss (gain) from past experience different
from that assumed 4,689 28 949 582
Net transition obligation 22 27 1,103 1,203
Adjustment to recognize minimum liability (3,777) - - (912)
--------- --------- -------- --------
Prepaid (accrued) pension cost $ (2,554) $ 623 $ 1,385 $ (67)
--------- --------- -------- --------
--------- --------- -------- --------
Net pension cost for both plans included the following components:
1995 1994 1993
(dollars in thousands)
Service cost of benefits earned during the period $ 1,171 $ 1,271 $ 1,113
Interest cost on projected benefit obligation 1,936 2,044 1,900
Actual return on plan assets (4,057) (1,101) (1,485)
Deferral of unrecognized loss (gain) and amortization, net 2,916 (524) 82
Amount recognized due to settlement - 16 -
-------- ------- --------
$ 1,966 $ 1,706 $ 1,610
-------- ------- --------
-------- ------- --------
The following table sets forth the approximate effects on the projected
benefit obligations resulting from amendments to the pension plan and from
the change in the discount rate from 8.75% to 7.25%:
Supplemental
Pension Retirement
Plan Plan
------- ------------
(dollars in thousands)
Effect of change in discount rate $ 4,500 $ 700
Effect of amendment to pension plan $ 1,800 $ (300)
The following assumptions were used to determine the projected benefit
obligation and expected return on assets at December 31:
1995 1994 1993
Pension plan:
Discount rate:
Nonretired lives 7.25% 8.75% 7.50%
Retired lives 7.25% 8.75% 6.00%
Long-term rate of return on plan assets 9.00% 8.50% 8.50%
Rate of increase in future compensation levels 5.00% 5.00% 5.00%
Supplemental retirement plan:
Discount rate 7.25% 8.75% 7.50%
Long-term rate of return on plan assets 8.50% 8.50% 8.50%
Rate of increase in future compensation levels 5.00% 5.00% 5.00%
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 401(k) plan. Under the terms of the 401(k)
plan, the Company will match each employee's contribution to the 401(k) plan
at a rate of 50% 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 $458,000, $474,000, and $370,000 for 1995, 1994, and 1993,
respectively.
The Company's health care plan provides Postretirement Benefits Other
than Pensions (PBOP), consisting of medical and prescription drug benefits,
to its retired employees hired prior to June 1, 1992, and their eligible
dependents. The Company has been recording PBOP expense, as provided in SFAS
No. 106, "Employers' Accounting for Postretirement Benefits Other than
Pensions", since January 1, 1993. The Company defers the portion of the
annual PBOP accrual attributable to Washington regulated operations in excess
of the cash basis of recording these expenses. This approach is consistent
with WUTC policy. The amounts so deferred have been $1,028,000, $1,892,000,
and $1,938,000 in 1995, 1994, and 1993 respectively. The Company has filed
a general rate case in the State of Washington, requesting recovery of these
deferred amounts. Management believes that the rates to be granted in this
rate case will include recognition of these amounts, as well as recognition
of on going PBOP expenses, as measured under SFAS No. 106. An adverse
decision by the WUTC could result in a material difference in the reported
amounts.
Amounts accrued for PBOP, not including the above mentioned deferrals,
consist of the following components:
1995 1994 1993
(dollars in thousands)
Service cost $ 366 $ 523 $ 510
Net interest cost 1,114 1,151 1,105
Actual return on plan assets (627) 12 --
Net amortization and deferral 934 551 657
------- ------- -------
$ 1,787 $ 2,237 $ 2,272
------- ------- -------
------- ------- -------
The Company's policy is generally to fund the plan to the extent
allowable under Internal Revenue Service rules. The following table sets
forth the health care plan's funded status.
1995 1994
(dollars in thousands)
Accumulated postretirement benefit
obligation (APBO):
Retirees $ 4,058 $ 3,814
Fully eligible active plan
participants 5,948 4,797
Other active plan participants 7,168 5,571
-------- ---------
17,174 14,182
Plan assets, at fair value, primarily
common stocks and corporate bonds 4,194 2,498
-------- ---------
Funded status (12,980) (11,684)
Unrecognized transition obligation 11,169 11,826
Unrecognized (gain) loss 349 (1,462)
-------- ---------
Accrued postretirement benefit cost $ (1,462) $ (1,320)
-------- ---------
-------- ---------
The assumed health care cost trend rate used in measuring the APBO is
10% for 1996, trending down to 5.5% at 2005. At January 1, 1995, the census
and per capita claims cost assumptions were updated, resulting in a reduction
in the APBO of approximately $1.2 million. The assumed discount rate used in
determining the APBO was 7.25% at December 31, 1995, and 8.75% at December
31, 1994. The effect of the decrease in the discount rate was an increase of
approximately $2.6 million in the APBO at December 31, 1995. A one
percentage point increase in the assumed health care cost trend rate for each
year would increase the APBO by approximately 16.6% and the service and
interest cost components of net postretirement health care cost by
approximately 16.9%.
NOTE 10 - GAS SERVICE CONTRACTS
The Company has entered into various transportation, supply, storage,
and peaking service contracts to assure that adequate supplies of gas will be
available to provide firm service to its core customers and to meet its
obligations under long-term non-core customer agreements. These contracts,
which have maturities ranging from one to 30 years, provide that the Company
must pay a fixed demand charge each month.
One gas supply contract requires the Company to take 10,037,500 therms
annually or the seller can reduce its commitment to provide that minimum
amount. Two other gas supply contracts require that the Company take 100% of
all tendered gas volumes up to the maximum daily limit each day during the
remaining life of the agreements. The total
36
contract quantity for these two agreements is 76,000,000 therms. All three
of these contracts have primary terms that end on November 1, 1996. Another
contract has a 42% take requirement, equaling an obligation of 41,475,315
therms per year through 2004. Among the Company's multi-year agreements, a
15-year contract for winter-only ( October through March) supply has a 70%
minimum take requirement, which equates to a purchase requirement of
9,841,650 therms per year. Finally, the Company has entered into various
agreements for the winter of 1995-96 whose minimum take requirements total
49,370,000 therms.
The remaining gas supply contracts do not require the Company to take
any gas, but the various suppliers are obligated to provide up to a maximum
of 80,300,000 therms annually. The Company's minimum obligations under these
contracts are set forth in the following table. The amounts are based on
current contract prices, which are subject to change.
STORAGE AND
FIRM GAS PEAKING
SUPPLY TRANSPORTATION SERVICE TOTAL
(dollars in thousands)
1996 $ 38,280 $ 27,310 $6,210 $ 71,800
1997 19,597 26,998 5,190 51,785
1998 18,511 26,998 5,059 50,568
1999 13,096 26,816 4,241 44,153
2000 12,693 26,780 4,052 43,525
Thereafter 51,892 363,979 56,107 $471,978
-------- -------- ------ --------
$154,069 $498,881 $80,859 $733,809
-------- -------- ------ --------
-------- -------- ------ --------
Purchases under these contracts for 1993, 1994, and 1995, including
commodity purchases, as well as demand charges have been as follows:
STORAGE AND
FIRM GAS PEAKING
SUPPLY TRANSPORTATION SERVICE TOTAL
(dollars in thousands)
1993 $50,036 $18,691 $4,179 $72,906
1994 $54,695 $22,751 $4,639 $82,085
1995 $45,223 $28,548 $4,722 $78,493
37
NOTE 11- CONTINGENCIES
The Company was notified by the Department of Ecology of the State of
Washington that it is a "potentially liable person" as a result of
contamination in the area of the Company's underground storage tanks at its
Sunnyside, Washington office. The Company has provided $455,000 to date for
the estimated costs of the cleanup. The Company believes that the remaining
reserves of $89,000 are adequate to complete the remediation.
During the first quarter of 1995, a claim related to environmental
contamination from a manufactured gas plant previously owned by a predecessor
corporation of the Company was filed by the present property owner. The
claim requested that the Company assume responsibility for investigation and
possible cleanup of alleged contamination on the property. A consultant has
been retained by the property owner to evaluate the nature and extent of any
contamination. To date the consultant has reported that contamination
consistent with manufactured gas operations is present, but there is no
estimate of the cost of remediation. To the extent the Company may be
responsible for all or part of such cost, it expects to seek contribution
from other site owners and its insurers, and would seek appropriate rate
relief to the extent of any remaining expense incurred.
Various lawsuits, claims, and contingent liabilities may arise from time
to time from the conduct of the Company's business. None of those now
pending, in the opinion of management, is expected to have a material effect
on the Company's financial position, results of operations, or liquidity.
NOTE 12 - REVENUES FROM MAJOR CUSTOMER
In 1995, no one customer accounted for more than 10% of gas revenues.
In 1994, one customer accounted for approximately $20,215,000 in gas
revenues. This represents 10.5% of total 1994 revenues; however, margins
derived from this customer were less than 3% of total margin. Outstanding
accounts receivable from this customer at December 31, 1994, totaled
$2,144,000, which represents December 1994 consumption. In 1993 no one
customer accounted for more than 10% of gas revenues.
38
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 necessarily 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 and/or estimation methodologies may have a
material effect on the estimated fair value amounts.
The estimated fair value amounts of financial instruments at December 31
are shown as follows:
1995 1994
CARRYING ESTIMATED CARRYING ESTIMATED
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
(dollars in thousands)
Assets:
Cash and cash equivalents $ 2,197 $ 2,197 $ 3,949 $ 3,949
Notes receivable, including
current maturities 3,235 3,234 3,903 3,955
Accounts receivable 26,483 26,483 28,885 28,885
Securities available for sale -- -- 1,466 1,466
Redeemable preferred stock 6,851 7,324 7,217 6,924
Liabilities:
Long-term debt 102,100 111,615 100,000 93,187
Notes payable 32,000 32,000 14,501 14,501
Current maturities of long-term debt -- -- 5,000 5,096
CASH AND CASH EQUIVALENTS, ACCOUNTS RECEIVABLE, AND NOTES PAYABLE: The
carrying amounts of these items are a reasonable estimate of their fair
value.
NOTES RECEIVABLE, REDEEMABLE PREFERRED STOCK, AND LONG-TERM DEBT:
Interest rates that are currently available to the Company for issuance of
instruments with similar terms and remaining maturities are used to estimate
fair value.
SECURITIES AVAILABLE FOR SALE: Fair values are based on quoted market
prices.
39
NOTE 14 - INTERIM RESULTS OF OPERATIONS (UNAUDITED)
QUARTER ENDED
DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31,
1995 1995 1995 1995
(thousands except per share data)
Operating revenues $ 56,907 $ 26,512 $ 34,715 $ 64,610
Gas costs and revenue taxes 34,892 16,028 21,833 41,585
-------- -------- -------- --------
Operating margin 22,015 10,484 12,882 23,025
Cost of operations 11,680 11,475 11,768 11,679
-------- -------- -------- --------
Earnings from operations 10,335 (991) 1,114 11,346
Interest and other, net 2,470 2,425 2,366 2,303
-------- -------- -------- --------
Earnings before income taxes 7,865 (3,416) (1,252) 9,043
Income taxes 2,666 (1,099) (369) 3,310
Preferred dividends 131 136 136 136
-------- -------- -------- --------
Net earnings (loss) $ 5,068 $ (2,453) $ (1,019) $ 5,597
-------- -------- -------- --------
-------- -------- -------- --------
Earnings (loss) per share $ 0.56 $ (0.27) $ (0.11) $ 0.63
-------- -------- -------- --------
-------- -------- -------- --------
QUARTER ENDED
DECEMBER 31, SEPTEMBER 30, JUNE 30, MARCH 31,
1994 1994 1994 1994
(thousands except per share data)
Operating revenues $ 62,533 $ 28,867 $ 36,264 $ 64,746
Gas costs and revenue taxes 40,836 19,705 24,863 44,179
-------- -------- -------- --------
Operating margin 21,697 9,162 11,401 20,567
Cost of operations 11,551 10,950 11,431 11,230
-------- -------- -------- --------
Earnings from operations 10,146 (1,788) (30) 9,337
Interest and other, net 2,844 1,939 1,835 1,782
-------- -------- -------- --------
Earnings before income taxes 7,302 (3,727) (1,865) 7,555
Income taxes 2,748 (1,397) (590) 2,744
Preferred dividends 136 141 140 141
-------- -------- -------- --------
Net earnings (loss) $ 4,418 $ (2,471) $ (1,415) $ 4,670
-------- -------- -------- --------
-------- -------- -------- --------
Earnings (loss) per share $ 0.50 $ (0.28) $ (0.16) $ 0.54
-------- -------- -------- --------
-------- -------- -------- --------
40
INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULE
Cascade Natural Gas Corporation
and Subsidiaries
We have audited the consolidated financial statements of Cascade Natural Gas
Corporation and subsidiaries as of December 31, 1995 and 1994, and for each
of the three years in the period ended December 31, 1995, and have issued our
report thereon dated February 5, 1996; such consolidated financial statements
and report are included in Part II of this Annual Report on Form 10-K. Our
audits also included the financial statement schedule of Cascade Natural Gas
Corporation, listed in Item 14(a)2. This financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express
an opinion based on our audits. In our opinion, such 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
February 5, 1996
41
SCHEDULE II
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
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
- -------------------------- ----------- ---------- ----------- ----------- ----------
Allowance for Doubtful
Accounts:
Year ended:
December 31, 1993 $ 399 279 188 $490
December 31, 1994 $ 490 340 369 $461
December 31, 1995 $ 461 330 366 $425
Note: Accounts receivable written off, net of recoveries
Valuation Reserve - Notes Receivable
December 31, 1994 $ 0 550 577 $1,127
December 31, 1995 $1,127 122 $1,249
Valuation Reserve -
Investments
December 31, 1994 $ 0 150 $150
December 31, 1995 $ 150 0 $150
42
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
43
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Refer to the information regarding directors under the caption "Election
of Directors" on pages 1 through 3 of the Proxy Statement issued to
Shareholders for the 1996 Annual Meeting (the 1996 Proxy Statement), which
information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
Refer to the information regarding executive compensation set forth in
the 1996 Proxy Statement, under "Executive Compensation" on pages 7, 8, and
9, and under "Compensation Committee Interlocks and Insider Participation" on
page 9, which information is incorporated herein by reference. Certain
information concerning the executive officers of the Company is set forth in
Part I, under the caption "Executive Officers of the Registrant."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Refer 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 1996 Proxy
Statement, which information is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Refer to the information regarding certain relationships and
transactions under the caption "Compensation Committee Interlocks and Insider
Participation" on page 9 of the 1996 Proxy Statement, which information is
incorporated herein by reference.
44
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 for the Years Ended December 31,
1995, 1994, and 1993
Consolidated Balance Sheets, December 31, 1995 and 1994
Consolidated Statements of Common Shareholders' Equity for the Years Ended
December 31, 1995, 1994, and 1993
Consolidated Statements of Cash Flows for the Years Ended December 31,
1995, 1994, and 1993
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:
Refer 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:
No reports on Form 8-K were filed for the quarter ended December 31, 1995.
On February 21, 1996, the Registrant filed a report on Form 8-K, dated
February 7, 1996, to report the change in its fiscal year to a fiscal year
ending September 30. The Registrant will file a transition report on Form
10-K covering the period commencing on January 1, 1996, and ending on
September 30, 1996.
45
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
March 27, 1996 By /s/ J. D. Wessling
- -------------------- --------------------
Date J. D. Wessling
Vice President - Finance, Chief
Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Chairman of the Board,
Chief Executive Officer
/s/ W. Brian Matsuyama and Director March 27, 1996
- ------------------------- (Principal Executive Officer) ---------------
W. Brian Matsuyama Date
President and
/s/ Ralph E. Boyd Chief Operating Officer March 27, 1996
- ------------------------- ---------------
Ralph E. Boyd Date
/s/ J. D. Wessling Vice President - Finance, March 27, 1996
- ------------------------ Chief Financial Officer ---------------
J. D. Wessling (Principal Financial Officer) Date
/s/ James E. Haug Treasurer and Chief March 27, 1996
- ------------------------- Accounting Officer ---------------
James E. Haug (Principal Accounting Officer) Date
/s/ Carl Burnham, Jr. Director March 27, 1996
- ------------------------- ---------------
Carl Burnham, Jr. Date
/s/ Melvin C. Clapp Director March 27, 1996
- ------------------------- ---------------
Melvin C. Clapp Date
/s/ David A. Ederer Director March 27, 1996
- ------------------------- ---------------
David A. Ederer Date
/s/ Howard L. Hubbard Director March 27, 1996
- ------------------------- ---------------
Howard L. Hubbard Date
/s/ Larry L. Pinnt Director March 27, 1996
- ------------------------- ---------------
Larry L. Pinnt Date
/s/ Brooks G. Ragen Director March 27, 1996
- ------------------------- ---------------
Brooks G. Ragen Date
/s/ Andrew V. Smith Director March 27, 1996
- ------------------------- ---------------
Andrew V. Smith Date
/s/ Mary A. Williams Director March 27, 1996
- ------------------------- ---------------
Mary A. Williams Date
46
INDEX TO EXHIBITS
Exhibit
No. Description
- ---- -----------
3.1 Restated Articles of Incorporation of the Registrant as amended through
March 25, 1996.
3.2 Restated Bylaws of the Registrant. Incorporated by reference to
Exhibit 3-(2) to the Registrant's annual report on Form 10-K for the
year ended December 31, 1990.
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 Amendment to Rights Agreement dated June 15, 1993, between the
Registrant and The Bank of New York. Incorporated by reference to
Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the
quarter ended June 30, 1993.
10.1 Letter Agreement dated April 28, 1995 between CanWest Gas Supply U.S.A.,
Inc. and the Registrant for Winter Peaking Supply - 1995 through 1998. A
PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL
TREATMENT.
10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1) dated
January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.2 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1993 (1993 Form 10-K).
10.3 Service agreement (assigned Storage Gas Service under Rate Schedule
SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation
and the Registrant. Incorporated by reference to Exhibit 10.3 to the
Registrant's 1993 Form 10-K.
10.4 Service Agreement (Liquefaction -- Storage Gas Service under Rate
Schedule SGS-1) dated January 12,1994, between Northwest Pipeline
Corporation and the Registrant. Incorporated by reference to
Exhibit 10.4 to the Registrant's 1993 Form 10-K.
10.5 Gas Purchase Agreement dated November 1, 1990, between Mobil Oil Canada
and the Registrant. Incorporated by reference to Exhibit 10-6 to the
1991 Form 10-K.
10.6 Amendment to Gas Purchase Agreement dated August 30, 1991, between Mobil
Oil Canada and the Registrant. Incorporated by reference to Exhibit
10(h)(2) to the Registrant's registration statement on Form S-2, No.
33-52672 (the 1992 Form S-2).
10.7 Amendment to Natural Gas Purchase Agreement dated September 1, 1993,
between Canadian Hydrocarbons Marketing, Inc., and the Registrant.
Incorporated by reference to Exhibit 10.1 to amendment no. 1 to the
Registrant's quarterly report on Form 10-Q/A for the quarter ended
September 30, 1993.
47
10.9 Long Term Gas Sales Agreement dated August 26, 1993, between Canadian
Hydrocarbons Marketing Inc., and the Registrant. Incorporated by
reference to Exhibit 10.2 to amendment no. 1 to the Registrant's
quarterly report on Form 10-Q/A for the quarter ended September 30,
1993.
10.10 Gas Sale Agreement dated November 1, 1993, between Mobil Natural Gas
Inc. and the Registrant. Incorporated by reference to Exhibit 10.10
to the Registrant's 1993 Form 10-K.
10.11 Agreement for Sale and Purchase of Gas dated November 1, 1993, as
amended by Letter Amendment dated December 8, 1993, between Mobil
Natural Gas, Inc., and the Registrant. Incorporated by reference to
Exhibit 10.11 to the Registrant's 1993 Form 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 1992 Form S-2.
10.12.1 Amendments dated August 20, 1992, November 1, 1992, October 20, 1993,
and December 17, 1993, to Replacement Firm Transportation Agreement
dated July 31, 1991, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.12.1 to the
Registrant's 1993 Form 10-K.
10.13 Firm Transportation Service Agreement dated April 25, 1991, between
Pacific Gas Transmission Company and the Registrant (1993 expansion).
Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2.
10.14 Firm Transportation Service Agreement dated October 27, 1993, between
Pacific Gas Transmission Company and the Registrant. Incorporated by
reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K.
10.17 Storage Agreement dated July 23, 1990, between Washington Water Power
Company and the Registrant. Incorporated by reference to Exhibit 10(v)
to the 1992 Form S-2.
10.17.1 Letter agreement dated May 26, 1995, amending the Storage Agreement
dated July 23, 1990, between Washington Water Power Company and the
Registrant.
10.18 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.18 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1994.
10.19 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated
January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.19 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.20 Service Agreement (Firm Redelivery Transportation Agreement under rate
Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.20 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.
10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources,
Inc. and the Registrant. Incorporated by reference to Exhibit 10.21 to
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994.
10.22 Amended and restated Natural Gas Sales Agreement dated August 17,
1994, between Westcoast Gas Services, Inc. and Registrant which
replaces and substitutes for the Kingsgate Gas Sales Agreement dated
September 23, 1960. Incorporated by reference to Exhibit 10.22 to the
Registrant's Annual Report on Form 10-K for the year ended December 31,
1994.
48
10.23 Firm Transportation Service Agreement dated November 4, 1994, between
Pacific Gas Transmission and the Registrant, effective November 1,
1995. Incorporated by reference to Exhibit 10.23 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1994.
10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest
Pipeline Corporation and Registrant. Incorporated by reference to
Exhibit 10.24 to the Registrant's Annual Report on Form 10-K for the
year ended December 31, 1994.
10.25 Prearranged Permanent Capacity Release of Firm Natural Gas
Transportation Agreements dated November 30, 1993 between Tenaska
Gas Co., Tenaska Washington Partners, L.P. and Registrant.
Incorporated by reference to Exhibit 10.25 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1994.
10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between
Tenaska Gas Co., Tenaska Washington Partners, L.P., and Registrant.
Incorporated by reference to Exhibit 10.26 to the Registrant's Annual
Report on Form 10-K for the year ended December 31, 1994.
10.27 Agreement for Peaking Gas Supply Service dated November 22, 1991,
between Longview Fibre Company and Registrant. Incorporated by
reference to Exhibit 10.27 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1994.
10.28 Letter Agreement dated October 24, 1995 between Westcoast Gas
Services, Inc. and the Registrant for Winter Peaking Supply - 1995
through 1998. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR
CONFIDENTIAL TREATMENT.
10.29 1991 Director Stock Award Plan of the Registrant.* Incorporated by
reference to Exhibit 10(n) to the 1992 Form S-2.
10.30 Executive Supplemental Income Retirement Plan of the Registrant and
Supplemental Benefit Trust as amended and restated as of May 1, 1989,
as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by
reference to Exhibit 10(o) to the 1992 Form S-2.
10.31 Employment agreement between the Registrant and W. Brian Matsuyama.*
Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
10.32 Employment agreement between the Registrant and Jon T. Stoltz.*
Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2.
12. Statement regarding computation of ratio of earnings to fixed charges
and preferred dividend requirements.
21. A list of the Registrant's subsidiaries is omitted because the
subsidiaries considered in the aggregate as a single subsidiary do not
constitute a significant subsidiary.
23. Consent of Deloitte & Touche LLP to the incorporation of their report
in the Registrant's registration statements.
27. Financial Data Schedule.
- ---------------
* Management contract of compensatory plan or arrangement.
49