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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 or 15 (d) of the
Securities Exchange Act of 1934
For the fiscal year ended December 31, 1993 Commission File Number 1-7196
CASCADE NATURAL GAS CORPORATION
(Exact name of registrant as specified in its charter)
Washington 91-0599090
(State of incorporation or organization) (IRS Employer
Identification Number)
222 Fairview Avenue North
Seattle, Washington 98109
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code (206) 624-3900
Securities registered pursuant to Section 12 (b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
Common stock, par value
$1 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
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 the Form 10-K. X
The aggregate market value of the voting stock held by nonaffiliates of the
Registrant as of the close of business on February 28, 1994, was
$143,092,888.
As of the close of business on February 28, 1994, Registrant had outstanding
8,602,716 shares of common stock.
Portions of the Registrant's definitive proxy statement for its 1994 Annual
Meeting of Shareholders are incorporated by reference into Part III hereof.
CASCADE NATURAL GAS CORPORATION
Annual Report to the Securities and Exchange Commission
on Form 10-K
For the Year Ended December 31, 1993
Table of Contents
Part I Page
Items
Item 1 - Business 1
Item 2 - Properties 9
Item 3 - Legal Proceedings 9
Item 4 - Submission of Matters To a Vote of Security Holders 9
- Executive Officers of the Registrant 10
Part II
Item 5 - Market for Registrant's Common Equity and Related
Shareholder Matters 11
Item 6 - Selected Financial Data 12
Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operation 14
Item 8 - Financial Statements and Supplementary Data 17
Item 9 - Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 46
Part III
Item 10 - Directors and Executive Officers 46
Item 11 - Executive Compensation 46
Item 12 - Security Ownership of Certain Beneficial
Owners and Management 46
Item 13 - Certain Relationships and Related Transactions 46
Part IV
Item 14 - Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 46
Signatures 47
Index to Exhibits 48
PART I
Item 1 - Business
General
Cascade Natural Gas Corporation (Cascade or the Corporation) 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, 1993, there were 110,441 residential customers, 21,781
commercial customers, 329 firm industrial customers and 30 traditional
interruptible customers, all of which are classified as core customers. In
addition, there were 87 non-core customers. In 1993, the core customers
provided 73% of the operating margin (up from 71% in 1992) while consuming
31.0% of the total gas deliveries, down from 31.3% in 1992. The non-core
customers (including transportation service) provided the remaining operating
margin of 27% (down from 29% in 1992) while consuming 69.0% of the total
throughput, up from 68.7% in 1992.
The Corporation is subject to regulation with respect to, among other
matters, rates, systems of accounts and issuance of securities by the
Washington Utilities and Transportation Commission (WUTC) and the Oregon
Public Utility Commission (OPUC). The Corporation is not subject to direct
regulation by the Federal Energy Regulatory Commission (FERC), but is
significantly affected by the FERC's orders which regulate interstate
pipelines serving the Corporation.
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 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 Corporation is also subject to state regulation with respect to
integrated resource planning and has filed its second Integrated Resource
Plan (IRP) in draft form with both the WUTC and the OPUC. The IRP
(previously least cost plan) shows the Corporation's plan for the best set of
gas 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 Corporation's forecast of growth in customers and volume
throughput for a twenty-year period. In addition, the IRP sets forth the
Corporation's demand side management goals of achieving certain conservation
levels in customer usage. Corporation investments in cost-effective demand
side resources are recoverable in rates in both Washington and Oregon.
The IRP also sets forth the Corporation's supply side management plans
regarding transportation capacity and gas supply acquisition over a twenty-
year period. The Corporation 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
Corporation 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 Corporation by giving it the opportunity to obtain input from regulators
and the public concurrently with making these important strategic decisions.
Until the Corporation receives final regulatory approval of these
decisions in the context of a rate case, the Corporation cannot predict with
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certainty the extent to which the integrated resource planning process will
affect its rates.
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.
OPERATING STATISTICS
(dollars in thousands except per therm and per customer data)
1993 1992 1991 1990 1989
Gas Distribution Revenue:
Firm:
Residential. . . . . . . $ 46,456$ 37,424 $ 37,260$ 33,737$ 34,868
Commercial . . . . . . . 46,870 38,797 40,092 38,802 42,551
Industrial . . . . . . . 10,931 8,715 8,343 8,403 22,048
Interruptible:
Commercial . . . . . . . 2,954 2,927 3,068 3,158 6,617
Industrial . . . . . . . 1,845 1,877 2,212 2,888 57,891
Non-core. . . . . . . . . 70,923 56,149 58,535 67,974 5,504
Total gas
sales revenue . . . . . 179,979 145,889 149,510 154,962 169,479
Transportation revenue . 7,087 6,423 4,658 5,381 3,841
Total gas distribution
revenue . . . . . . . . $187,066$152,312 $154,168$160,343$173,320
Gas Deliveries (thousands of therms):
Firm:
Residential. . . . . . . 87,812 71,211 71,661 64,673 60,149
Commercial . . . . . . . 102,256 85,303 89,873 86,497 85,633
Industrial . . . . . . . 28,208 22,585 21,984 21,941 69,402
Interruptible:
Commercial . . . . . . . 4,730 4,608 5,319 5,396 16,204
Industrial . . . . . . . 5,925 5,944 7,350 10,507 254,787
Non-core. . . . . . . . . 269,483 255,707 277,716 301,983 24,684
Total sales. . . . . . . 498,414 445,358 473,903 490,997 510,859
Transportation deliveries 240,448 159,779 84,918 112,588 81,109
Total deliveries. . . . . 738,862 605,137 558,821 603,585 591,968
Customers (monthly averages):
Firm:
Residential. . . . . . . 104,334 96,621 89,306 82,640 77,340
Commercial . . . . . . . 21,166 20,266 19,316 18,475 17,582
Industrial . . . . . . . 318 308 308 300 300
Interruptible:
Commercial . . . . . . . 17 17 18 19 30
Industrial . . . . . . . 13 16 18 19 68
Non-core. . . . . . . . . 86 80 77 76 5
Total. . . . . . . . . . 125,934 117,308 109,043 101,529 95,325
Year-end totals. . . . . 132,668 123,356 114,734 106,933 99,956
(Operating Statistics continued on next page)
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OPERATING STATISTICS
(dollars in thousands except per therm and per customer data)
1993 1992 1991 1990 1989
Average Annual Consumption
Per Customer (therms):
Residential. . . . . . . 842 737 802 783 778
Commercial-firm. . . . . 4,831 4,209 4,653 4,682 4,870
Average Annual Revenue
Per Customer:
Residential. . . . . . . $ 445 $ 387 $ 417 $ 408 $ 451
Commercial-firm. . . . . $ 2,214 $ 1,914 $ 2,076 $ 2,100 $ 2,420
Average Rate per Therm:
Firm:
Residential. . . . . . . $0.5290 $0.5255 $0.5199 $0.5217 $0.5797
Commercial . . . . . . . $0.4584 $0.4548 $0.4461 $0.4486 $0.4969
Industrial . . . . . . . $0.3875 $0.3859 $0.3795 $0.3830 $0.3177
Interruptible:
Commercial (excluding
facilities charges) . . $0.3169 $0.3194 $0.3166 $0.3156 $0.3186
Industrial . . . . . . . $0.3114 $0.3158 $0.3010 $0.2749 $0.2272
Non-core. . . . . . . . . $0.2632 $0.2196 $0.2108 $0.2251 $0.2230
Transportation. . . . . . $0.0295 $0.0402 $0.0549 $0.0478 $0.0474
Average Cost per Therm
For Gas Purchased . . . . $0.2434 $0.2055 $0.1958 $0.1963 $0.2153
Heating Degree Days
System Average (30-year
average 5,675). . . . . 6,099 5,075 5,454 5,396 5,507
Maximum Day Send Out
(1,000 therms) Including
Transportation . . . . . 3,485 2,687 2,567 2,854 3,238
Average Daily Send Out
(1,000 therms) Including
Transportation . . . . . 2,019 1,653 1,531 1,654 1,622
Employees-End of Year. . . 467 466 460 450 443
- 3 -
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. The Corporation is
also a shipper on the Pacific Gas Transmission Company (PGT) system. PGT
owns and operates a gas transmission line that extends from the gas fields in
Alberta, Canada 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
Corporation 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.
Presently, baseload requirements for Cascade's core market group are
provided by two major domestic and six major Canadian gas supply contracts
with various expiration dates for 1995 through 2008 and totalling 503,840
therms per day. These contracts are supplemented by storage gas inventories
including the assignment of Clay Basin inventory providing for 200,000 therms
per day and a maximum 1994-95 inventory of 8,361,200 therms. Two additional
agreements for storage gas cover periods of peak demand. One, with
Northwest, 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, extends 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. Cascade has entered into a contract with one
of its major industrial customers whereby it may reduce firm deliveries to
that customer by 150,000 therms per day up to a seasonal total of 3,000,000
therms. This contract expires on September 30, 2015. Cascade also owns a
propane air peak shaving plant with a daily capacity of 60,000 therms and has
liquified natural gas storage available under an agreement with Northwest
which extends to October 31, 2014. Under this agreement, Cascade is entitled
to receive up to 600,000 therms per day and to a maximum, renewable inventory
of 5,622,000 therms.
Cascade maintains a diversified portfolio of natural gas supplies.
During 1993, Cascade purchased approximately 6.2% from Northwest, 41.9% from
other firm gas supply contracts, 48.3% from 30-day spot market contracts and
3.5% from customer assigned gas purchase contracts. In addition, 240,448,000
therms of customer purchased supplies were transported across Cascade
facilities.
Current Federal Energy Regulatory Commission (FERC) Matters:
On November 1, 1993, and pursuant to FERC Order No. 636, as
supplemented by FERC Order No. 636A, 636B and 636C (Order 636), Northwest
completed the conversion of its remaining sale service to firm transportation
service and ceased nearly all activities as a merchant of natural gas. Also
on November 1, 1993, PGT undertook the same conversion and is now primarily a
transportation pipeline. With the completion of the Northwest conversion,
Cascade holds 2,090,490 therms per day of firm transportation capacity. As
part of the Northwest conversion, the Corporation took direct assignment of
313,350 therms per day of firm PGT transportation capacity and contracted for
an additional 74,460 therms of wintertime only firm capacity on the PGT
system.
- 4 -
Interstate pipelines that cease being gas sellers face the cost of
buying down take-or-pay commitments contained in contracts with their own gas
suppliers. Such costs were relatively small on Northwest's system, and to
the extent they were passed on, state regulators allowed Cascade to include
them in rates to its customers. The FERC since has determined that
$37,000,000 of these past charges were allocated among Northwest's customers
in an impermissible manner. Proceedings to reallocate these costs are now in
progress. To the extent Cascade's final allocation differs from the
original, it will seek to pass on the difference to its customers in rates.
Even though PGT is still restructuring supply contracts which were
entered into between PGT and a sister company for the sole purpose of
providing sales service to their parent, Pacific Gas and Electric Company in
California, Cascade and other northwest shippers negotiated a settlement that
capped their PGT Gas Supply Restructuring (GSR) costs at approximately 1.3%
of the anticipated final approved GSR costs. Cascade's allocation was
$350,000 and the Corporation opted to make a one time payment earlier this
year, thereby discharging all obligations to the PGT GSR costs associated
with Cascade's original PGT capacity regardless of the eventual PGT
settlement total. The Corporation may have some additional exposure to a
small amount of GSR costs that may be collected from all shippers through a
volumetric surcharge assessed on its 1993 and 1995 PGT expansion capacity.
Cascade is seeking full recovery of this payment in its rates, as was done
with respect to Northwest transition costs.
Because Northwest has been working toward the transformation from sales
to open access transportation of natural gas since 1988, Cascade has
experienced very little operational impact or transition costs from the
implementation of Order 636. The April 1, 1993 shift to straight fixed
variable rates mandated by Order 636 did not, by itself, increase total
pipeline transportation costs to Cascade, but did result in a greater share
of such costs being attributable to low load factor customers of Cascade.
Additional pipeline costs were experienced with the November 1, 1993
completion of the first of Northwest's and PGT's expansion projects. The
rates presently being collected, subject to refund, reflect a rolled-in
methodology currently being challenged through FERC rate case proceedings, by
Cascade and several other shippers advocating an incremental rate design.
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 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.
- 5 -
Territory Served and Franchises
The population of communities served by Cascade totaled approximately
700,000 at the end of 1993 compared to 665,000 at the end of 1992, a 5.3%
increase.
Cascade has all the franchises necessary for the distribution of
natural gas in the communities it serves in Washington and Oregon with the
exception of one city franchise in Washington the renewal of which is being
negotiated. 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 1994 to 2065. Management
has not incurred difficulties in renewing franchises when they expire and
does not expect any problems in the future.
Customers
Residential and commercial customers principally use natural gas for
space heating and water heating. This market is very weather-sensitive. See
"Seasonality," below.
Of its non-core customers, 15 accounted for approximately 31% of
Cascade's total 1993 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. No one customer accounted for as much as
10% of gas revenues.
Seasonality
Weather is an important factor affecting gas revenues because of the
large number of customers using gas for space heating. In 1993, 64.5% of
operating revenues and 96.8% 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 sells in a competitive market for natural gas. Cascade
competes with residual fuel oil and other alternative energy sources for
industrial boiler uses and oil and electricity for residential and commercial
space and water heating uses.
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 a significant advantage over
electricity in over 90% (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 at parity with respect to
electricity furnished by those utilities for space heating and water heating
uses. Cascade has increased its efforts in attaining a positive customer
growth in the residential and commercial market over the last several years
by aggressively meeting consumers' needs. Through its wholly-owned
subsidiary, Cascade Land Leasing Co., the Corporation provides loans to
customers to finance the purchase and installation of energy efficient gas
appliances.
- 6 -
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
Corporation's competitive position. From December 1991 through January 1992
and again from December 1992 through February 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 Corporation competes with
other sources of natural gas because of the potential for bypass of the
Corporation's facilities. Bypass refers to actual or prospective customers
which install their own facilities and connect directly to an upstream
pipeline and thereby "bypass" the distribution company's service. The
Corporation 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. BPA increased rates by approximately 14% in October,
1993.
Environmental
The Corporation 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 Corporation purchased several of the gas
distribution facilities that it operates today. Among the acquired
facilities, the Corporation has identified to date 12 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 sites and have
found no hazardous substances at levels requiring remediation. Based on
information received to date, management is not aware of hazardous substances
present at any of the sites at levels that would require remediation.
The Corporation is in the process of remediating a site that was
contaminated by underground diesel and gasoline storage tanks. See Note 9
under Notes to Consolidated Financial Statements.
Capital Expenditures
Capital expenditures for 1994 are budgeted for $35,100,000. Including
the 1994 capital budget, the Corporation will have spent slightly over
$103,000,000 in new plant in the three years ended in 1994, compared to
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$108,000,000 in the nine years from the end of 1982 through 1991. Included in
the budget are distribution facilities to serve the fourth cogeneration plant
on the Corporation's system. The contracts for service to the four
cogeneration plants are expected to yield virtually level payments over the
15- to 25-year contract lives of the which should recover the capital
investment in the facilities and provide a return to shareholders over their
term. With level payments, projected rates of return are low in the early
years and increase significantly over time as the Corporation's investment is
depreciated. Therefore, the significant capital expenditures incurred in
1992, 1993 and budgeted for 1994, will likely produce a dampening effect on
earnings in the short term with a longer term effect of strengthening the
earnings flow.
No budgets have been prepared beyond 1994, however, the Corporation
expects that capital expenditures will total approximately $110,000,000 to
$140,000,000 over the following five years.
Non-Utility Subsidiaries
Cascade has six non-utility subsidiaries. These subsidiaries are
engaged in the following businesses, respectively; financing Cascade
customers' purchases of energy-efficient appliances; marketing a gas
measurement chart scanner; ownership and licensing of the technology related
to a gas measurement chart scanner; exploring for natural gas; 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 Corporation, do
not currently have a significant impact on Cascade's financial condition or
the results of its operation.
Personnel
At December 31, 1993, Cascade had 467 employees. Of the total
employees, 209 are represented by the International Chemical Workers Union.
The present contract with the union extends to April 1, 1996, and thereafter
until terminated by either party on 60-days' notice.
- 8 -
Item 2 - Properties
At December 31, 1993, Cascade's utility plant investments included
approximately 3,558 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 2,162 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 16 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 Corporation also owns a propane air plant in Yakima,
Washington, with a capacity of 60,000 therms per day used for peak load
shaving.
Item 3 - Legal Proceedings
See last paragraph under "Business - Environmental".
Item 4 - Submission of Matters To a Vote of Security Holders
None
- 9 -
Executive Officers of the Registrant
The Executive Officers of the Corporation, as of March 1, 1994, are as
follows:
Year
Became
Name Office Age Officer
Melvin C. Clapp Chairman of the Board and
Chief Executive Officer 60 1972
W. Brian Matsuyama President 47 1987
Donald E. Bennett Executive Vice President,
Chief Financial Officer
and Secretary 61 1978
Jon T. Stoltz Senior Vice-President,
Planning and Rates 47 1981
Ralph E. Boyd Vice-President and Chief
Operating Officer 57 1988
O. LeRoy Beaudry Vice-President,
Consumer and Public 55 1981
Affairs
Calvin R. Steele Vice-President,
Data-Processing 54 1991
King C. Oberg Vice-President, 53 1993
Gas Supply
James E. Haug Treasurer and Chief
Accounting Officer 45 1981
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 Corporation 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.
King C. Oberg has been employed by the Corporation since January 2,
1989. From 1963 through October 1988, he held various positions in gas
measurement and accounting with ENRON Corp. of Houston Texas.
- 10 -
PART II
Item 5 - Market for Registrant's Common Equity and Related Shareholder
Matters
The Common Stock is traded on the New York Stock Exchange under the
symbol CGC. At February 28, 1994, there were approximately 6,745 record
holders of the Common Stock. The following table shows for the periods
indicated the high and low sales prices of, and the per share dividends paid
on, the Common Stock in each case as adjusted for stock splits.
Market and Dividend Information
Common stock sales price ranges Dividends
1993 1992 1993 1992
Quarter High Low High Low
First 17 15 1/2 15 5/8 13 3/4 .23 1/3 .22 2/3
Second 17 3/4 16 5/8 15 1/8 13 7/8 .23 2/3 .23 1/3
Third 19 1/2 17 1/4 16 5/8 14 3/8 .23 2/3 .23 1/3
Fourth 19 3/8 17 15 7/8 14 3/4 .23 2/3 .23 1/3
The Corporation'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, 1994, to holders of record on
January 15, 1994. Future dividend action will depend on the earnings and
financial condition of the Corporation and other relevant factors.
- 11 -
Item 6 - Selected Financial Data
Statements of Operations
(dollars in thousands except per share data)
1993 1992 1991 1990 1989
Operating Revenues:
Gas sales $179,979 $145,889 $149,510 $154,962 $169,479
Transportation revenue 7,087 6,423 4,658 5,381 3,841
Other operating income 388 154 144 172 166
187,454 152,466 154,312 160,515 173,486
Less: Gas purchases 113,500 90,320 90,903 97,392 110,407
Revenue taxes 11,095 8,997 9,362 9,192 10,039
Operating Margin 62,859 53,149 54,047 53,931 53,040
Cost of Operations:
Operating expenses 28,536 26,262 24,630 22,428 21,144
Depreciation and
amortization 9,151 8,388 7,704 7,282 6,829
Property and payroll
taxes 3,757 3,516 3,361 3,373 3,005
Income taxes 5,224 2,817 4,206 4,547 5,178
46,668 40,983 39,901 37,630 36,156
Overrun Penalty Income 1,305
Earnings from operations 16,191 12,166 15,451 16,301 16,884
Nonoperating Expense (Income):
Interest 7,038 7,478 7,793 8,374 8,063
Interest charged to
construction (323) (218) (156) (98) (89)
6,715 7,260 7,637 8,276 7,974
Amortization of debt
issuance expense 562 402 362 373 370
Other 20 (339) (199) (724) 58
7,297 7,323 7,800 7,925 8,402
Net Earnings Before Cumulative
Effect of Change in Accounting
Method 8,894 4,843 7,651 8,376 8,482
Cumulative Effect of Change in
Accounting Method 209
Net Earnings 9,103 4,843 7,651 8,376 8,482
Preferred Dividends 580 595 148 154 178
Net Earnings Available to
Common Shareholders $ 8,523 $ 4,248 $ 7,503 $ 8,222 $ 8,304
Common Stock Outstanding:
End of Year 8,566,374 7,613,589 6,630,956 6,564,789 6,494,403
Average 7,914,858 6,681,263 6,586,671 6,518,520 6,452,913
Net Earnings per Common Share:
Before cumulative effect
of change in accounting
method $ 1.05 $ 0.64 $ 1.14 $ 1.26 $ 1.29
Cumulative effect of
change in accounting
method 0.03
Net Earnings per Common
Share $ 1.08 $ 0.64 $ 1.14 $ 1.26 $ 1.29
(Selected Financial Data continued on next page)
- 12 -
1993 1992 1991 1990 1989
Retained Earnings:
Beginning of the year $13,455 $15,655 $14,142 $11,674 $8,893
Net earnings after
preferred dividends 8,523 4,248 7,503 8,222 8,304
Common dividends paid
in cash (7,902) (6,448) (5,990) (5,754) (5,523)
End of the year $14,076 $13,455 $15,655 $14,142 $11,674
Capital Structures:
Common shareholders'
equity $85,702 $69,199 $57,225 $54,931 $51,705
Redeemable preferred
stocks $ 7,528 $ 7,951 $ 8,254 $ 2,444 $ 2,898
Debt:
Long-term debt $87,000 $74,677 $57,060 $60,803 $60,080
Notes payable 13,502 13,000 8,500 1,500 0
Current maturities of
long-term debt 0 0 3,500 2,500 3,925
$100,502 $87,677 $69,060 $64,803 $64,005
Total capital $193,732 $164,827 $134,539 $122,178 $118,608
Financial Ratios:
Return on common
shareholders' equity 11.00% 6.72% 13.38% 15.42% 16.62%
Common stock dividend
payout ratio 92.72% 151.82% 79.83% 69.98% 66.51%
Dividends paid in cash
per common share $ 0.94 $ 0.93 $ 0.90 $ 0.87 $ 0.85
Fixed charge coverage
(before income tax
deduction):
Times interest earned 2.86 1.97 2.45 2.48 2.62
Times interest and
preferred dividends
earned 2.55 1.76 2.39 2.41 2.53
Book value per year-end
share of common stock$ 10.00 $ 9.09 $ 8.63 $ 8.37 $ 7.96
Utility Plant:
Utility plant -
end of year $315,297 $283,871 $249,027 $230,769 $217,132
Accumulated depreciation 117,925 109,184 100,927 93,824 87,883
Net plant $197,372 $174,687 $148,100 $136,945 $129,249
Construction expenditures$ 32,990$ 35,335 $ 19,669 $ 16,415 $ 12,902
Total assets $252,690 $224,685 $191,471 $181,080 $175,319
- 13 -
Item 7 - Management's Discussion of the Results of Operations and Financial
Conditions
Results of Operations
1993 vs 1992
The continuing strong customer growth coupled with reasonably normal weather
(7.5% colder than normal) pushed total year earnings as well as fourth quarter
earnings to new record levels. Net earnings to common shareholders for 1993
were $8,523,000 or $1.08 per share compared to $4,248,000 or $0.64 per share in
1992. Fourth quarter net earnings to common shareholders were $5,005,000
compared to $3,962,000 in the 1992 fourth quarter. Earnings per share were
$0.59 in the 1993 quarter and $0.57 in the 1992 quarter.
Margin and Volume Changes
Between 1993 and 1992
Margin Contribution (thousands): Therms Deliveries (thousands):
Increase(Decrease) Increase(Decrease)
Amount Percent Amount Percent
Core 8,058 21.4% 39,280 20.7%
Non-Core 1,652 10.7% 94,445 22.7%
Total 9,710 18.3% 133,725 22.1%
The successful sales of common stock in November, 1992 and June, 1993,
increased the number of shares outstanding, affecting per share comparisons for
both the year and the quarter. All per share numbers reflect the three for two
stock split which was effective on December 20, 1993.
Acquisition of new customers continued at the healthy rate of 7.5% in 1993.
Residential customers increased 8.3% in 1993 over 1992. Therm deliveries to the
core market increased 20.7% while therm deliveries to the non-core market were
up 22.7%. The significant increase in deliveries to the non-core market,
primarily in the latter half of 1993, reflects the beginning of commercial
operation for the second cogeneration plant on the Corporation's system.
Operating expenses were up 8.7% ($2,274,000) in 1993. Payroll and fringe
benefit cost increases accounted for 85% of the increase. The Corporation
adopted Statement of Financial Accounting Standard (SFAS) No. 106 Employers'
Accounting for Postretirement Benefits other than Pensions, which accounted for
a portion of the fringe benefit cost increase. Depreciation expense increased
9.1% ($763,000) as a result of the significant additions to utility plant in
1993 and prior years. Income taxes were up 85.4% ($2,407,000) over 1992. The
increase is primarily due to the improvement in earnings.
Interest expense was down 5.9% ($440,000) from the 1992 level as a result of
the refinancing of higher cost debt that was accomplished in mid 1992 and early
1993. Interest charged to construction was up 48% ($105,000) as the result of
the use of more short-term debt in 1993. Amortization of debt issuance expense
was up 40% ($160,000) in 1993 reflecting the costs incurred to refinance the
higher cost debt mentioned above. Other expense reflects termination of all
interests and the writeoff of all remaining costs ($244,000) associated with
the drilling activities in northwestern Washington as well as other valuation
reserves.
The results for 1993 include the effect of adopting, in the first quarter of
1993, SFAS No. 109, Accounting for Income Taxes, which resulted in a one time
credit to earnings of $209,000 or $0.03 per share.
Results of Operations
1992 vs 1991
A return to more normal weather in the fourth quarter of 1992 produced
strong earnings for the quarter but, not sufficient to offset the impact of the
record warm temperatures in the first quarter of 1992. Therm deliveries to the
- 14 -
core market were up 11.7% in the 1992 quarter compared to the prior year
producing a 21.4% increase in margins from the core category over the similar
period in 1991. While this significant improvement over the fourth quarter of
1991 was largely attributable to the return to more normal weather, the
continuing strong customer growth of 7.5% also had an impact.
Total margin for 1992 was down $898,000 (1.7%), however, margin from the
core customers was down $1,764,000 (4.5%) reflecting the impact of the warmer
than normal weather experienced through most of the year. The increase in
margin from the non-core customers reflected the full year impact of the first
cogeneration plant on the system as well as an increase in customers. Total
volumes for 1992 were up 46,315,000 therms (8.3%) but deliveries to the core
customers were down 6,536,000 therms (3.3%).
Margin and Volume Changes
Between 1992 and 1991
Margin Contribution (thousands):Therms Deliveries (thousands):
Increase(Decrease) Increase(Decrease)
Amount Percent Amount Percent
Core (1,764) (4.5%) (6,536) (3.3%)
Non-Core 866 (5.9%) 52,851 14.6%
Total (898) (1.7%) 46,315 8.3%
While earnings for all of 1992 were depressed as a result of the significant
decline in degree days (6.9% fewer than 1991 and 10.6% warmer than normal),
continuing customer growth contributes to improved profitability under normal
weather. The Corporation continued to add new customers at a record pace and
while the vast majority of the new customers in 1992 came from the residential
class, the number of non-core customers increased by 7.8%.
Operating expenses increased 6.6% in 1992 over 1991 and this compares
favorably to the 9.8% increase experienced in 1991 over 1990. Employee costs,
including fringe benefits, accounted for 80% ($1,299,000) of the increase.
Staffing increases and increased medical costs were the primary driving force
behind the increases.
Depreciation expense increased 8.9% as a result of the significant growth in
utility plant (up 11.6%) required to serve the additional customers. The
decline in income tax expense is the result of lower earnings. Costs of
$157,000 or $0.03 per share representing costs incurred in connection with
natural gas exploration were charged to expenses in the fourth quarter.
Liquidity and Capital Resources
The Corporation invested $32,990,000 in new utility plant in 1993. Internal
cash generation, after cash dividends, funded approximately 20%. The low level
of internal cash generation for funding construction was the result of
returning in excess of $8,778,000 to customers from a Northwest Pipeline
Corporation refund received in 1989 as a result of the settlement of their rate
case. These items coupled with the seasonal nature of the Corporation's
business required the use of short and long-term debt in 1993. To provide the
short-term debt requirements the Corporation has $25,000,000 of committed lines
from two banks which are used to support a money market facility of a similar
amount. The Corporation also has $30,000,000 of uncommitted lines from three
banks. The long-term debt requirements were funded through the issuance of two
$5,000,000 Medium-Term Notes which mature in 1998 and bear interest rates of
5.77% and 5.78%. The Corporation also sold $24,000,000 of 20 year Medium-Term
Notes in February 1993 at interest rates ranging from 7.95% to 8.01% to refund
the 9.875% Debentures Due 2013 in the amount of $21,677,000.
On June 22, 1993, the Corporation sold 575,000 shares of common stock
through a public offering at $26.125 per share. The net proceeds of $14,435,000
- 15 -
were used to reduce short-term indebtedness. Effective December 20, 1993, the
Corporation issued a three for two common stock split.
In November 1993, an additional $50,000,000 of Medium-Term notes were
registered with the Securities and Exchange Commission.
In December, 1993, changes were implemented to the existing Dividend
Reinvestment Plan to allow residential customers of the Corporation residing in
Oregon and Washington to purchase stock through the Plan with an initial
investment of $250. While there is no way of predicting the level of customer
response, it is expected that this program will provide, at a lower cost, a new
stream of equity capital to the Corporation to fund utility construction
expenditures.
The Corporation has a capital budget for 1994 of $35,100,000 which will be
funded through internal cash generation and the short and long-term debt
facilities mentioned above.
Effects of Inflation
Changing prices have had a minimal impact on the Corporation's operating
margins. The effects of price changes in purchased gas costs and the cost of
transporting gas to the Corporation's system are passed onto 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. Since the Corporation's last general
rate adjustment in 1989, growth in the customer base has mitigated the negative
effect of inflation on income from operations.
- 16 -
Item 8 - Financial Statements and Supplementary Data
The financial statements and supplementary data listed in the following
index are filed as part of this report.
Index to Financial Statements and Supplementary Data
Page No.
Independent Auditors' Report on the
Consolidated Financial Statements 18
Consolidated Financial Statements:
Statements of Net Earnings Available to Common
Shareholders for the Years ended
December 31, 1993, 1992 and 1991 19
Balance Sheets as of December 31, 1993 and 1992 20
Statements of Common Shareholders' Equity for the
Years ended December 31, 1993, 1992 and 1991 22
Statements of Cash Flows for the Years ended
December 31, 1993, 1992 and 1991 23
Notes to Consolidated Financial Statements for the three
years ended December 31, 1993 24
Independent Auditors' Report on the Financial
Statement Schedules 36
Financial Statement Schedules:
Schedule V - Utility Plant 37
Schedule VI - Accumulated Depreciation of
Utility Plant 38
Schedule VIII - Valuation and Qualifying
Accounts 39
Schedule IX - Short-Term Borrowings 40
Schedule X - Supplementary Income Statement
Information 41
- 17 -
Independent Auditor's 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,
1993 and 1992, and the related consolidated statements of net earnings
available to common shareholders, common shareholders' equity, and cash flows
for each of the three years in the period ended December 31, 1993. These
financial statements are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Cascade Natural Gas Corpora-
tion and subsidiaries as of December 31, 1993 and 1992, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1993, in conformity with generally accepted accounting
principles.
As discussed in Notes 6 and 7 to the financial statements, the Company
adopted Statement of Financial Accounting Standards (SFAS) No. 109, Accounting
for Income Taxes, and SFAS No. 106, Employers' Accounting for Postretirement
Benefits other than Pensions, for the year ended December 31, 1993.
Deloitte & Touche
Seattle, Washington
February 1, 1994
- 18 -
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Statements of Net Earnings Available to Common Shareholders
Years ended December 31, 1993, 1992, and 1991
1993 1992 1991
(dollars in thousands except per share data)
Operating Revenues:
Gas sales $179,979 $145,889 $149,510
Transportation revenue 7,087 6,423 4,658
Other operating income 388 154 144
187,454 152,466 154,312
Less:
Gas purchases 113,500 90,320 90,903
Revenue taxes 11,095 8,997 9,362
Operating Margin 62,859 53,149 54,047
Cost of Operations:
Operating expenses 28,536 26,262 24,630
Depreciation and amortization 9,151 8,388 7,704
Property and payroll taxes 3,757 3,516 3,361
Income taxes 5,224 2,817 4,206
46,668 40,983 39,901
Overrun Penalty Income --- --- 1,305
Earnings from operations 16,191 12,166 15,451
Nonoperating Expense (Income):
Interest 7,038 7,478 7,793
Interest charged to construction (323) (218) (156)
6,715 7,260 7,637
Amortization of debt issuance expense 562 402 362
Other 20 (339) (199)
7,297 7,323 7,800
Net Earnings Before Cumulative Effect of
Change in Accounting Method 8,894 4,843 7,651
Cumulative effect of change in accounting
method (Note 6) 209 --- ---
Net Earnings 9,103 4,843 7,651
Preferred Dividends 580 595 148
Net Earnings Available to Common
Shareholders $ 8,523 $ 4,248 $ 7,503
Earnings Per Common Share:
Before cumulative effect of change
in accounting method $ 1.05 $ 0.64 $ 1.14
Cumulative effect of change in accounting
method 0.03 --- ---
Net Earnings Per Common Share $ 1.08 $ 0.64 $ 1.14
Average Shares Outstanding (Note 3) 7,914,858 6,681,263 6,586,671
See notes to consolidated financial statements
- 19 -
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
ASSETS
December 31,
1993 1992
(dollars in thousands)
Utility Plant $310,288 $272,464
Less accumulated depreciation 117,925 109,184
192,363 163,280
Construction work in progress 5,009 11,407
197,372 174,687
Other Assets:
Investments, at cost 1,149 1,225
Notes receivable, less current
maturities 3,508 4,379
4,657 5,604
Current Assets:
Cash and cash equivalents 3,138 3,332
Temporary investments 757 ---
Accounts receivable, less allowance
of $490 and $399 for doubtful
accounts 26,539 24,440
Current maturities of notes receivable 1,331 1,661
Materials, supplies, and inventories 6,416 5,410
Prepaid expenses and other assets 444 845
38,625 35,688
Deferred Charges 12,036 8,706
$252,690 $224,685
See notes to consolidated financial statements
- 20 -
COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES
December 31,
1993 1992
(dollars in thousands)
Common Shareholders' Equity:
Common stock, par value $1 per share (Note 3)
Authorized, 10,000,000 shares; issued and
outstanding, 8,566,374 and 5,075,726 shares $ 8,566 $ 5,076
Additional paid-in capital 63,060 50,668
Retained earnings (Note 5) 14,076 13,455
85,702 69,199
Redeemable Preferred Stocks, aggregate redemption
amount of $7,826 and $8,288 (Note 2) 7,528 7,951
Long-term Debt (Note 5) 87,000 74,677
Current Liabilities:
Notes payable (Note 4) 13,502 13,000
Accounts payable 22,362 16,194
Property, payroll, and excise taxes 3,960 3,716
Dividends and interest payable 3,665 3,881
Other current liabilities 2,395 1,920
45,884 38,711
Deferred Credits:
Gas cost changes 3,568 14,168
Income taxes (Note 6) 13,708 12,513
Investment tax credits 3,747 4,013
Other 5,553 3,453
26,576 34,147
Commitments and Contingencies (Notes 8 and 9) --- ---
$252,690 $224,685
See notes to consolidated financial statements
- 21 -
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
Common Stock Additional
Paid-in Retained
Shares Par Value Capital Earnings
(dollars in thousands)
BALANCE, January 1, 1991 4,376,526 $4,377 $36,412 $14,142
Common stock issued:
Sales to employee stock ownership plan 2,260 2 41
Dividend reinvestment program 35,370 35 688
Employee Savings Plan and Retirement Trust
(401(k)) 6,481 7 139
Redemption of preferred stock (5)
Issuance of preferred stock (126)
Cash dividends:
Common stock, $1.36 per share (5,990)
Preferred stock, Senior, $.55 per share (141)
7.85% cumulative preferred stock, $.11 per share (7)
Net earnings 7,651
Balance, December 31, 1991 4,420,637 4,421 37,149 15,655
Common stock issued:
Public offering 600,000 600 12,352
Employee Savings Plan and Retirement Trust
(401(k)) 17,802 18 384
Director stock award plan 1,200 1 25
Dividend reinvestment program 36,087 36 771
Redemption of preferred stock (13)
Cash dividends:
Common stock, $1.40 per share (6,448)
Preferred stock, Senior, $.55 per share (124)
7.85% cumulative preferred stock, $7.85 per share (471)
Net earnings 4,843
Balance, December 31, 1992 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 800 1 19
Dividend reinvestment program 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, $.95 per share (7,902)
Preferred stock, Senior, $.55 per share (109)
7.85% cumulative preferred stock, $7.85 per share (471)
Net earnings 9,103
Balance, December 31, 1993 8,566,374 $8,566 $63,060 $14,076
See notes to consolidated financial statements
- 22 -
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years ended December 31, 1993, 1992, and 1991
1993 1992 1991
(dollars in thousands)
Operating Activities:
Net earnings . . . . . . . . . . . . $9,103 $4,843 $7,651
Adjustments to reconcile net earnings to net cash
provided by operating activities:
Depreciation . . . . . . . . . . 10,268 9,342 8,598
Amortization of gas cost changes (10,119) (3,070) (3,695)
Increase in deferred income taxes 758 1,976 920
Cumulative effect of change in accounting
method . . . . . . . . . . . (209) -- --
Decrease in deferred investment tax credits(266)(274)(295)
Cash provided (used) by changes in operating
assets and liabilities:
Accounts receivable. . . . . . (2,099) (3,515) 2,311
Income taxes . . . . . . . . . 98 268 (1,028)
Inventories. . . . . . . . . . (601) (244) (675)
Gas cost changes . . . . . . . (482) (366) 2,257
Deferred items . . . . . . . . 490 613 (145)
Accounts payable and accrued expenses6,5633,918 (82)
Other. . . . . . . . . . . . . 456 517 213
Net cash provided by operating activities13,96014,008 16,030
Investing Activities:
Capital expenditures . . . . . . . . (32,990)(35,335)(19,669)
New consumer loans . . . . . . . . . (2,352) (3,265) (4,033)
Receipts on consumer loans . . . . . 3,533 3,994 3,120
Other. . . . . . . . . . . . . . . . (747) -- --
Net cash used by investing activities(32,556)(34,606)(20,582)
Financing Activities:
Issuance of preferred stock. . . . . -- -- 5,874
Issuance of common stock . . . . . . 14,937 13,380 189
Redemption of preferred stock. . . . (455) (315) (195)
Proceeds from long-term debt . . . . 33,686 47,551 --
Repayment of long-term debt. . . . . (22,761)(37,414) (2,743)
Proceeds from notes payable, net . . 501 4,500 7,000
Dividends paid . . . . . . . . . . . (7,506) (6,237) (5,415)
Net cash provided by financing activities18,40221,465 4,710
Net Increase (Decrease) in Cash and
Cash Equivalents . . . . . . . . . . (194) 867 158
Cash and Cash Equivalents:
Beginning of year. . . . . . . . . . 3,332 2,465 2,307
End of year. . . . . . . . . . . . . $3,138 $3,332 $2,465
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest (net of amounts capitalized)$6,744 $6,058 $6,486
Income taxes . . . . . . . . . . . $2,598 $1,050 $4,736
- 23 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Years Ended December 31, 1993
Note 1 - Summary of Significant Accounting Policies
Cascade Natural Gas Corporation and its subsidiaries (the
Corporation) follow the Uniform System of Accounts prescribed by
the Federal Energy Regulatory Commission and is subject to the
jurisdiction of the Washington Utilities and Transportation
Commission (WUTC) and the Oregon Public Utility Commission
(OPUC). Substantially all of the Corporation's operations relate
to the distribution of natural gas to retail customers.
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.; CGC Resources, Inc.; Fibre Graphics, Inc.; and
Metrology One, 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 40 years, with a composite rate
of approximately 3.5%.
Investments:
Investments consist primarily of real estate, classified as
nonutility property carried at original cost less accumulated
depreciation.
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 8.5% to 12%.
Materials, supplies, and inventories:
Materials, supplies, and inventories include patented chart
- 24 -
scanners held for resale which are recorded at the lower of cost
(specific identification) or market. Inventories of gas and
other materials and supplies 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 (see Note 7), and deferrals of postretirement
health care expenses (see Note 7). 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 Corporation accrues estimated revenues for gas delivered
but not billed to residential and commercial customers from the
meter reading dates to month end.
Overrun penalty income is recognized when the Corporation has
determined that significant penalties are known and measurable
and reasonably enforceable. Due to the unusual and infrequent
nature of significant overrun penalty income, the Corporation has
elected to report this income separately on the statement of net
earnings.
Gas cost changes:
Gas cost changes consist primarily of the effect of decreases
in purchased gas costs which have not yet been reflected in rates
charged to customers. The effect 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
periods are subject to the approval of the regulatory agencies
and are generally one to two years.
Federal income taxes:
The Corporation 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 Corporation elected to record depreciation on 1981
and subsequent utility plant additions under the Accelerated Cost
Recovery System. This election required the Corporation to
provide deferred income taxes on the difference between
depreciation computed for financial statement and tax reporting
purposes beginning in 1981 (see Note 6). 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.
- 25 -
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 Corporation
considers all investments with a purchased maturity of
approximately three months or less to be cash equivalents.
Reclassifications:
Certain reclassifications have been made in the 1992 financial
statements to conform to the classifications used in 1993.
Note 2 - Redeemable Preferred Stocks
1993 1992 1991
(dollars in thousands)
Shares Amount Shares Amount Shares
Amount
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 213,157 1,951 244,719 2,254 264,397 2,444
Shares retired 45,481 423 31,562 303 19,678 190
Authorized, issued, and
outstanding at end of
year 227,676 $7,528 273,157 $7,951 304,719 $8,254
The Corporation must retire annually 42,948 shares of Senior preferred stock
through November 1, 1995, with further reductions as individual series are
fully retired. The shares may be purchased on the open market or redeemed at
$10 per share plus accrued dividends.
The 7.85% cumulative preferred stock may not be redeemed until maturity on
November 1, 1999.
The aggregate preferred stock redemption requirements based upon the
aforementioned redemption prices are: $284,000 in 1994, $425,000 in 1995, and
$250,000 in 1996, 1997, and 1998. The Corporation may, at its option, purchase
the required number of shares on the open market at less than the redemption
price.
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 and
all restrictive provisions of the long-term indebtedness agreements have been
satisfied.
- 26 -
Note 3 - Common Stock
At December 31, 1993, shares of common stock are reserved for issuance
as follows:
Number Purchase, conversion, contribution,
of shares or option price per share
Employee Savings Plan and Market closing price of common stock
Retirement Trust immediately prior to purchase by the
(401(k) plan) 80,276 Trustee.
Dividend reinvestment plan 823,962 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 12,000 Market closing price of common stock
on the date of the
Corporation's annual meeting.
916,238
Effective December 20, 1993, the Corporation 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 4 - Notes Payable
At December 31, 1993, the Corporation had two committed lines of credit
available, one of $20,000,000 and one of $5,000,000. These agreements expire
in 1996 and 1994, respectively, and provide for a commitment fee of .2% and
.15%, respectively. The committed lines are used as backup support for an
uncommitted facility of $25,000,000, of which $13,502,000 was outstanding at
December 31, 1993. In addition, the Corporation has uncommitted lines of
credit available of $10,000,000 each from three banks.
The average daily amount outstanding under these arrangements during 1993
was approximately $11,696,000 with a maximum month end borrowing of
$22,752,000. The effective weighted average interest rate (excluding
commitment fees) based upon daily amounts outstanding was 3.66%.
- 27 -
Note 5 - Long-term Debt
Long-term debt consists of the following:
1993 1992
(dollars in thousands)
9-7/8% debentures due 2013 $ -- $21,677
9.46% promissory note due 1995 5,000 5,000
Medium-term notes:
5.77% due 1998 5,000 --
5.78% due 1998 5,000 --
7.18% due 2004 4,000 4,000
7.32% due 2004 22,000 22,000
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 --
8.01% due 2013 10,000 --
7.95% due 2013 10,000 --
$87,000 $74,677
None of the long-term debt includes current maturities or sinking fund
requirements. The 9-7/8% debentures were called for redemption on March 1,
1993.
Various debt and credit agreements restrict the Corporation and its
subsidiaries as to indebtedness, payment of cash dividends on common stock, and
other matters. Under these restrictions, approximately $25,718,000 is
available for payment of dividends as of December 31, 1993.
During 1992, the Corporation entered into an interest rate swap agreement,
which expires on December 1, 1995, that effectively converts its 9.46%
$5,000,000 promissory note into a variable rate obligation. Under the terms of
this agreement, the Corporation makes payments at a floating rate which is
based on LIBOR and receives payments at a fixed rate. The net interest paid or
received is included in interest expense.
Note 6 - Income Taxes
The Corporation 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 Corporation. The
cumulative effect of adopting SFAS No. 109 on the Corporation's financial
statements was to increase net earnings by $209,000 ($.03 per share) in the
first quarter of 1993.
- 28 -
Under the provisions of SFAS No. 109, the Corporation 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 Corporation 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.
- 29 -
The provision for income tax expense consists of the following:
1993 1992 1991
(dollars in thousands)
Current tax expense $3,443 $ 451 $3,581
Alternative minimum tax
(credit carryforward) (665) 665 --
Deferred tax expense 2,668 1,975 920
Change in tax rates 44 -- --
Amortization of deferred
investment tax credits (266) (274) (295)
$5,224 $2,817 $4,206
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 includes
a charge of $44,000 ($.01 per share) 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:
1993 1992 1991
(dollars in thousands)
Statutory federal income
tax rate 35% 34% 34%
Income tax calculated at
statutory federal rate $4,941 $2,604 $4,031
Increase (decrease) resulting from:
State income tax, net of
federal tax benefit 106 15 104
Differences between book and
tax depreciation 441 513 474
Amortization of investment
tax credits (266) (274) (295)
Other 2 (41) (108)
$5,224 $2,817 $4,206
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
- 30 -
tax purposes. The tax effects of significant items comprising the
Corporation's net deferred tax liability are as follows:
(dollars in
thousands)
Deferred tax liabilities:
Differences between book and tax basis
of property $11,383
Debt refinancing costs 2,695
Retirement benefit obligations 410
Other 26
14,514
Deferred tax assets:
Retirement benefit obligations 450
Provision for doubtful accounts 175
Other 181
806
Net deferred tax liability $13,708
- 31 -
Note 7 - Retirement Plans
The Corporation'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 Corporation's policy is generally
to fund the plan to the extent allowable under Internal Revenue Service rules.
The Corporation 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.
To fund the plan, the Corporation has insured the lives of the executives.
The following table sets forth the funded status of the defined benefit
pension and supplemental retirement plans and amounts recognized in the
Corporation's financial statements:
Supplemental
Pension plan retirement plan
1993 1992 1993 1992
(dollars in thousands)
Actuarial present value of accumulated
benefit obligations:
Vested . . . . . . . . . . . . . . $ 21,579 $ 18,126 $ 2,285 $ 1,751
Nonvested . . . . . . . . . . . . . 239 79 138 118
$ 21,818 $ 18,205 $ 2,423 $ 1,869
Projected benefit obligation for services
rendered to date . . . . . . . . . $(25,823) $(20,349) $(3,130) $(2,581)
Plan assets at fair value, primarily common
stocks, corporate bonds, and life
insurance policies . . . . . . . . 21,076 19,079 2,079 1,788
Projected benefit obligation in excess of
plan assets (4,747) (1,270) (1,051) (793)
Unrecognized amounts:
Prior service cost . . . . . . . . 2,561 1,331 --- ---
Loss (gain) from past experience different
from that assumed . . . . . . . . 2,446 194 523 110
Net transition obligation . . . . . 33 38 1,303 1,403
Adjustment to recognize minimum liability (1,035) --- (1,119) (801)
Prepaid (accrued) pension cost . . . $ (742) $ 293 $ (344) $ (81)
- 32 -
Net pension cost for both plans included the following components:
1993 1992 1991
(dollars in thousands)
Service cost of benefits earned during the
period . . . . . . . . . . . . . . $1,113 $920 $874
Interest cost on projected benefit obligation $1,900 $1,625 $1,219
Actual return on plan assets . . . . (1,485) (1,234) (2,352)
Deferral of unrecognized loss (gain) and
amortization, net . . . . . . . . . 82 (130) 1,210
$1,610 $1,181 $ 951
The actuarial present value of accumulated plan benefits for the pension
plan at December 31, 1993, reflects an amendment effective April 1, 1993,
which increases benefits applicable to compensation earned since January 1,
1990. The actuarial present value of accumulated plan benefits for both
plans at December 31, 1993, reflect reductions in the discount rate and in the
assumed rate of increase in future compensation levels. The combination of
these changes increased the projected benefit obligation of the pension plan
and supplemental retirement plan by $2,200,000 and $134,000, respectively, at
December 31, 1993.
- 33 -
The following assumptions were used to determine the projected benefit
obligation and expected return on assets at December 31:
1993 1992 1991
Pension plan:
Discount rate:
Nonretired lives . . . . . . . . . 7.5% 8.5% 8.5%
Retired lives . . . . . . . . . . 6.0 6.0 6.0
Long-term rate of return on plan assets 8.5 8.5 8.5
Rate of increase in future compensation
levels 5.0 6.0 6.0
Supplemental retirement plan:
Discount rate . . . . . . . . . . . 7.5 8.5 8.5
Long-term rate of return on plan assets 8.5 8.5 8.5
Rate of increase in future compensation
levels 5.0 6.0 6.0
The Corporation 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 Corporation 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 Corporation recognized costs for
contributions to this plan of $370,000, $217,000, and $138,000 for 1993,
1992, and 1991, respectively.
Effective January 1, 1993, the Corporation adopted SFAS No. 106,
Employers' Accounting for Postretirement Benefits other than Pensions. SFAS
No. 106 requires the Corporation to accrue the estimated cost of future
retiree benefit payments during the years the employee provides services.
The Corporation previously recorded the cost of these benefits, which are
principally health care, as benefit payments were incurred. SFAS No. 106
allows recognition of the cumulative effect of the liability in the year of
the adoption, or the accrual of the obligation over a period of up to
20 years. The Corporation has elected to recognize this obligation of
approximately $13,100,000 over a period of 20 years.
The accrual of postretirement benefits other than pensions (PBOP) for
the year was $2,272,000. The accruals exceeded payments of these benefits
during the period by $1,938,000. As allowed by the policy of the WUTC,
$1,523,000 has been deferred, and included in deferred charges. Management
expects that these and prospective deferral amounts will be recovered in the
future through rates charged to customers. The remaining $415,000 is subject
to the jurisdiction of the OPUC. In accordance with OPUC policy, $309,000 has
been charged to operating expenses and $106,000 to construction.
Implementation of this Standard has resulted in a charge to net earnings
available to common shareholders of $202,000 ($.03 per share).
- 34 -
The Corporation's health care plan provides benefits for substantially
all of its retired employees hired prior to June 1, 1992, and their eligible
dependents. In 1992 and 1991, the Corporation recognized $239,000 and
$209,000, respectively, as an expense for postretirement health care benefits.
Net postretirement health care benefit cost for 1993 consisted of the
following components:
(dollars in
thousands)
Service cost . . . . . . . . $ 510
Net interest cost . . . . . . 1,105
Actual return on plan assets
Amortization of transition obligation 657
$2,272
The Corporation'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:
(dollars in
thousands)
Accumulated postretirement benefit obligation (APBO):
Retirees . . . . . . . . . . $3,722
Fully eligible active plan participants 5,611
Other active plan participants 7,807
17,140
Plan assets (interest bearing deposits), at
fair value 1,250
Funded status . . . . . . . . . . . . . (15,890)
Unrecognized transition obligation . . . . . 12,483
Unrecognized (gain) loss . . . . . . . . . . 2,719
Accrued postretirement benefit cost . . . . . $ (688)
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation is 11.5% for 1994, trending down to 6% at
2010. The assumed discount rate used in determining the accumulated
postretirement benefit obligation was 7.5%. A one percentage point increase
in the assumed health care cost trend rate for each year would increase the
accumulated postretirement benefit obligation by approximately 17% and the
service and interest cost components of net postretirement health care cost by
approximately 18%.
- 35 -
Note 8 - Gas Service Contracts
The Corporation 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 Corporation must pay a fixed demand charge each month.
One gas supply contract requires the Corporation to take 10,037,500
therms annually or the seller can reduce its commitment to provide that
minimum amount. Two other gas supply contracts, which expire in 1995, require
that the Corporation take 100% of all tendered gas volumes during the
remaining life of the agreements. These requirements are for 105,605,450
therms in 1994 and 87,956,320 therms in 1995. Another contract has a 42% take
requirement, equaling an obligation of 41,475,315 therms per year through
2004. Lastly, a 15-year contract for winter-only (October through March)
supply has a 70% minimum take requirement, which equates to a purchase
requirement of 9,868,688 therms per year.
The remaining gas supply contracts do not require the Corporation to
take any gas, but the various suppliers are obligated to provide up to a
maximum of 80,300,000 therms annually. The Corporation'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.
Firm gas Storage and
Supply Transportation peaking service Total
(dollars in thousands)
1994 $ 44,722 $ 21,018 $ 7,415 $ 73,155
1995 40,768 21,018 6,037 67,823
1996 20,633 21,018 4,320 45,971
1997 18,487 21,018 4,320 43,825
1998 18,099 21,018 4,320 43,437
Thereafter 90,335 178,712 47,338 316,385
$233,044 $283,802 $73,750 $590,596
Purchases under these contracts for 1991, 1992, and 1993, including
commodity purchases, as well as demand charges have been as follows:
Firm gas Storage and
Supply Transportation peaking service Total
(dollars in thousands)
1991 $ 44,803 $ 10,722 $ 3,623 $ 59,148
1992 45,812 10,201 3,944 59,957
1993 50,036 18,691 4,179 72,906
- 36 -
Note 9 - Contingencies
The Corporation 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 Corporation's underground storage tanks at
its Sunnyside, Washington office. The Corporation has provided $455,000 to
date for the estimated costs of the cleanup. The Corporation believes that
the remaining reserves of $181,000 are adequate to complete the remediation.
Various lawsuits, claims, and contingent liabilities may arise from
time to time from the conduct of the Corporation's business. None of those
now pending, in the opinion of management, is expected to have a material
effect on the Corporation's financial position or results of operations.
- 37 -
Note 10 - Fair Value of Financial Instruments
The following estimated fair value amounts have been determined by
the Corporation, 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
Corporation 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, 1993, are as follows:
Carrying Estimated
amount fair value
(dollars in thousands)
Assets:
Cash and cash equivalents $ 3,138 $3,138
Notes receivable, including
current maturities 4,839 4,984
Accounts receivable 26,539 26,539
Temporary investments 757 757
Redeemable preferred stock 7,528 7,482
Liabilities:
Long-term debt 87,000 93,705
Notes payable 13,502 13,502
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 Corporation for issuance of
instruments with similar terms and remaining maturities are used to estimate
fair value.
Temporary investments: Fair values are based on quoted market prices.
- 38 -
Note 11 - Interim Results of Operations (unaudited)
Earnings (loss) per share have been restated for the effect of the three for
two stock split in December 1993.
Quarter ended
March 31, June 30, September 30, December 31,
1993 1993 1993 1993
(dollars in thousands except per share data)
Operating revenues . . . . . . . . . . . $61,729 $37,141 $29,435 $59,149
Gas costs and revenue taxes. . . . . . . 38,993 26,127 20,637 38,838
Operating margin . . . . . . . . . . . 22,736 11,014 8,798 20,311
Cost of operations . . . . . . . . . . . 13,968 10,168 9,124 13,408
Earnings from operations . . . . . . . . 8,768 846 (326) 6,903
Interest and other, net. . . . . . . . . 2,213 1,682 1,644 1,758
Net earnings (loss) before cumulative effect
of change in accounting method . . . . . 6,555 (836) (1,970) 5,145
Cumulative effect of change in
accounting method . . . . . . . . . . . 209 -- -- --
Net earnings (loss) $ 6,764 $ (836) $(1,970) $5,145
Earnings (loss) per share:
Before cumulative effect of
change in accounting method . . . . . . . . . . $0.84 $(0.13) $ (0.25) $ 0.59
Cumulative effect of change in
accounting method 0.03 -- -- --
Earnings (loss) per share $0.87 $(0.13) $ (0.25) $ 0.59
Quarter ended
March 31, June 30, September 30, December 31,
1992 1992 1992 1992
(dollars in thousands except per share data)
Operating revenues . . . . . . . . . . . $47,155$27,676 $25,161 $52,474
Gas costs and revenue taxes. . . . . . . 30,209 18,025 16,986 34,097
Operating margin . . . . . . . . . . . 16,946 9,651 8,175 18,377
Cost of operations . . . . . . . . . . . 11,482 8,928 8,327 12,246
Earnings from operations . . . . . . . . 5,464 723 (152) 6,131
Interest and other, net. . . . . . . . . 1,728 1,751 1,822 2,022
Net earnings (loss). . . . . . . . . . . $3,736$(1,028) $(1,974) $4,109
Earnings (loss) per share. . . . . . . . $ 0.54$ (0.18) $ (0.32) $ 0.57
- 39 -
INDEPENDENT AUDITOR'S REPORT
Cascade Natural Gas Corporation
and Subsidiaries
We have audited the consolidated financial statements of Cascade Natural Gas
Corporation and subsidiaries as of December 31, 1993 and 1992, and for each of
the three years in the period ended December 31, 1993, and have issued our
report thereon dated February 1, 1994; 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 schedules of Cascade Natural Gas
Corporation, listed in Item 14(a)2. These financial statement schedules are
the responsibility of the Company's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial
statement schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material respects the
information shown therein.
DELOITTE & TOUCHE
Seattle, Washington
February 1, 1994
- 40 -
SCHEDULE V
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
UTILITY PLANT
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Balance at Additions Balance at
Beginning at Other End of
Description of Period Cost Retirements Changes Period
------------------------ ---------- ---------- ---------- ---------- ----------
YEAR ENDED DECEMBER 31, 1991:
Intangible plant $364 $364
Production plant 1,073 1,073
Transmission plant 14,311 14,311
Distribution plant 186,596 15,367 775 201,188
General plant 26,267 1,671 735 27,203
---------- ---------- ---------- ----------
Subtotal 228,611 17,038 1,510 0 244,139
Construction work in progress 2,158 2,730 4,888
---------- ---------- ---------- ---------- ----------
Total $230,769 $19,768 $1,510 $0 $249,027
========== ========== ========== ========== ==========
YEAR ENDED DECEMBER 31, 1992:
Intangible plant $364 $364
Production plant 1,073 1,073
Transmission plant 14,311 14,311
Distribution plant 201,188 26,279 549 226,918
General plant 27,203 3,628 1,033 29,798
---------- ---------- ---------- ----------
Subtotal 244,139 29,907 1,582 0 272,464
Construction work in progress 4,888 6,519 11,407
---------- ---------- ---------- ---------- ----------
Total $249,027 $36,426 $1,582 $0 $283,871
========== ========== ========== ========== ==========
YEAR ENDED DECEMBER 31, 1993:
Intangible plant $364 $364
Production plant 1,073 33 1,106
Transmission plant 14,311 14,311
Distribution plant 226,918 37,893 557 264,254
General plant 29,798 1,376 921 30,253
---------- ---------- ---------- ----------
Subtotal 272,464 39,302 1,478 0 310,288
Construction work in progress 11,407 (6,398) 5,009
---------- ---------- ---------- ---------- ----------
Total $283,871 $32,904 $1,478 $0 $315,297
========== ========== ========== ========== ==========
Land is included in utility plant as follows:
1993 1992 1991
---------- ---------- ----------
Production plant $54 $54 $54
Transmission plant 29 29 29
Distribution plant 310 310 311
General plant 2,408 2,408 2,295
---------- ---------- ----------
Total $2,801 $2,801 $2,689
========== ========== ==========
- 41 -
SCHEDULE VI
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
ACCUMULATED DEPRECIATION OF UTILITY PLANT
(Thousands of Dollars)
Column A Column B Column C Column D Column E Column F
Additions
Balance at Charged to Other Balance at
Beginning Costs and Charges End of
Description of Period Expenses Retirements (Note) Period
------------------------ ---------- ---------- ---------- ---------- ----------
Year ended:
December 31, 1991 $93,824 7,610 1,446 939 $100,927
========== ========== ========== ========== ==========
December 31, 1992 $100,927 8,294 1,280 1,243 $109,184
========== ========== ========== ========== ==========
December 31, 1993 $109,184 9,050 1,443 1,134 $117,925
========== ========== ========== ========== ==========
NOTE: Additions charged to other accounts as follows:
Year ended December 31,
----------------------------------
1993 1992 1991
Depreciation of equipment and warehouses
charged to clearing accounts and allocated
to operating and construction accounts on
the basis of usage $1,031 $991 $907
Portion of depreciation of office building
charged to construction accounts on the
basis of the use of floor space in the
building 139 127 117
Change as a result of increase (decrease)
in Retirement Work-In-Progress (36) 125 (85)
---------- ---------- ----------
$1,134 $1,243 $939
========== ========== ==========
- 42 -
SCHEDULE VIII
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, 1991 $387 199 --- 202 $384
==== ==== ==== ====
December 31, 1992 $384 249 --- 234 $399
==== ==== ==== ====
December 31, 1993 $399 279 --- 188 $490
==== ==== ==== ====
Note: Accounts receivable written off, net of recoveries
- 43 -
SCHEDULE IX
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
SHORT-TERM BORROWINGS
(Thousands of Dollars)
Column A Column B Column C Column D Column E
Maximum Average
Weighted Amount Amount
Balance at Average Outstanding Outstanding
Category of Aggregate at End of Interest During the During the
Short-term Borrowings Period Rate Period Period
------------------------ ---------- ---------- ---------- ----------
(Note)
Notes Payable
Year ended:
December 31, 1991 $8,500 5.67% $14,750 $3,594
========== ========== ========== ==========
December 31, 1992 $13,000 3.83% $31,502 $13,480
========== ========== ========== ==========
December 31, 1993 $13,502 3.66% $22,752 $11,696
========== ========== ========== ==========
Note - The average amount outstanding during the period is computed
by dividing the sum of daily outstanding balances by 360.
- 44 -
SCHEDULE X
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INCOME STATEMENT INFORMATION
(Thousands of Dollars)
Column A Column B
Charged to Costs and Expenses
Item for the Years Ended December 31,
----------------------------- ----------------------------------
1993 1992 1991
---------- ---------- ----------
Taxes, other than income taxes:
State excise $5,880 $4,811 $5,039
City franchise and occupation 4,843 3,896 4,038
Other revenue taxes 372 290 285
Real and personal property 2,478 2,325 2,247
Miscellaneous, principally
payroll 1,635 1,532 1,415
---------- ---------- ----------
$15,208 $12,854 $13,024
========== ========== ==========
Charged to -
Revenue taxes $11,095 $8,997 $9,362
Property & payroll tax expense 3,757 3,516 3,361
Construction work in progress
(payroll taxes) 356 341 301
---------- ---------- ----------
$15,208 $12,854 $13,024
========== ========== ==========
Maintenance and repairs, charged to
operating expenses $2,091 $1,824 $1,750
========== ========== ==========
Other items provided for in Rule 12-11 were less than 1% of revenues.
- 45 -
Item 9 - Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10 - Directors and Executive Officers of the Registrant
See the information regarding directors under the caption "Election of
Directors" on pages 1 through 3 of the Proxy Statement issued to Shareholders
for the 1994 Annual Meeting (the 1994 Proxy Statement), 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 11 - Executive Compensation
See the information regarding excutive compensation set forth in the 1994
Proxy Statement, under the caption "Report of Nominating and Compensation
Committee to the Shareholders" on page 5, under "Executive Compensation "on
pages 7 and 8 and under "Compensation Committee Interlocks and Insider
Participation" on page 9, which information is incorporated herein by
reference.
Item 12 - Security Ownership of Certain Beneficial Owners and Management
See the information on security ownership of certain beneficial owners and
management under the caption "Security Ownership of Certain Beneficial Owners
and Management" on page 4 of the 1994 Proxy Statement, which information is
incorporated herein by reference.
Item 13 - Certain Relationships and Related Transactions
See the information on certain relationships and transactions under the
caption "Compensation Committee Interlocks and Insider Participation" on page
9 of the Proxy Statement, which information is incorporated herein by
reference.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. and 2. For a list of the financial statements and financial statement
schedules filed herewith, see the index to financial statements and
supplementary data in Item 8 of this report.
(a) 3. For a list of the exhibits filed herewith, see the index to exhibits
following the signature pages 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, 1993.
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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 25, 1994 By /s/ Donald E. Bennett
Date Donald E. Bennett
Executive Vice President,
Chief Financial Officer,
Secretary and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
Chairman of the Board,
Chief Executive Officer
/s/ Melvin C. Clapp and Director March 25, 1994
Melvin C. Clapp
/s/ W. Brian Matsuyama President and Director March 25, 1994
W. Brian Matsuyama
Executive Vice President,
Chief Financial Officer,
/s/ Donald E. Bennett Secretary and Director March 25, 1994
Donald E. Bennett
Treasurer and Chief
/s/ James E. Haug Accounting Officer March 25, 1994
James E. Haug
/s/ Carl Burnham, Jr. Director March 25, 1994
Carl Burnham, Jr.
/s/ David A. Ederer Director March 25, 1994
David A. Ederer
/s/ Howard L. Hubbard Director March 25, 1994
Howard L. Hubbard
/s/ Brooks G. Ragen Director March 25, 1994
Brooks G. Ragen
/s/ Andrew V. Smith Director March 25, 1994
Andrew V. Smith
/s/ Mary A. Williams Director March 25, 1994
Mary A. Williams
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INDEX TO EXHIBITS
Exhibit
No. Description
3.1 Restated Articles of Incorporation of the Registrant as amended on
January 5, 1993, and May 10, 1993. Incorporated by reference to
Exhibit 4 to the Registrant's current report on Form 8-K dated June
2, 1993.
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(c) 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 Distribution Agreement dated December 6, 1993, among the Registrant
and Smith Barney Shearson Inc. and Merrill Lynch & Co., Merrill
Lynch, Pierce, Fenner & Smith Incorporated. Incorporated by
reference to Exhibit 1 to the Registrant's registration statement
Form S-3, No. 33-71286.
10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1)
dated January 12, 1994, between Northwest Pipeline Corporation and
the Registrant.
10.3 Service agreement (assigned Storage Gas Service under Rate Schedule
SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation
and the Registrant.
10.4 Service Agreement (Liquefaction -- Storage Gas Service under Rate
Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline
Corporation and the Registrant.
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.
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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 1992 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.
10.8 Natural Gas Sales Agreement dated November 1, 1990, as supplemented
by letter dated August 27, 1992, between Canadian Hydrocarbons
Marketing Inc. and the Registrant. Incorporated by reference to
Exhibit 10(k) to the 1992 Form S-2.
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.
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.
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.
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.
10.15 Amendment to Transportation Agreement dated August 20, 1992, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10(w) to the 1992 Form S-2.
10.16 Assignment and Amendment of Gas Purchase Contract dated September 30,
1991 (effective November 1, 1992) among Northwest Pipeline
Corporation, West Coast Energy Inc., West Coast Energy Marketing
Ltd., Canadian Hydrocarbons Marketing Inc., and the Registrant,
amending Kingsgate Gas Sales Agreement ("Kingsgate Gas Sales
Agreement") dated September 23, 1960, as amended by Letter Agreement
dated August 15, 1989, between
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Northwest Pipeline Corporation and West Coast Energy Inc.
Incorporated by reference to Exhibit 10(s) to the 1992 Form S-2.
10.16.1 Interim Pricing Arrangement dated November 4, 1993 between Canadian
Hydrocarbons Marketing, Inc. and the Registrant relating to the
Kingsgate Gas Sales Agreement.
10.17 Clay Basin Inventory Sales Agreement dated July 31, 1991, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10(t) to the 1992 Form S-2.
10.18 Storage Agreement dated July 23, 1991, between Washington Water Power
Company and the Registrant. Incorporated by reference to Exhibit
10(v) to the 1992 Form S-2.
10.19 Service Agreement (Firm Redelivery Transportation Agreement under
Rate Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994,
between Northwest Pipeline Company and the Registrant.
10.20 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 Company and the
Registrant.
10.21 Service Agreement (Firm Redelivery Transportation Agreement under
rate Schedule TF-2 for Cascade's LS-1) dated January 12, 1994,
between Northwest Pipeline Company and the Registrant.
10.22 1991 Director Stock Award Plan of the Registrant.* Incorporated by
reference to Exhibit 10(n) to the 1992 Form S-2.
10.23 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.
10.24 Employment agreement between the Registrant and W. Brian Matsuyama.*
Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
10.25 Employment agreement between the Registrant and Jon T. Stoltz.*
Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2.
10.26 Employment agreement between the Registrant and Ralph E. Boyd.*
Incorporated by reference to Exhibit 10(r) to the 1992 Form S-2.
12. Computation of Ratio of Earnings to Fixed Charges.
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 to the incorporation of their report in
the Registrant's registration statements.
* Management contract or compensatory plan or arrangement.
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