<PAGE>
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, 1994 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
Preferred Stock Purchase Rights 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, 1995 was $124,242,147.
As of the close of business on February 28, 1995, Registrant had outstanding
8,954,389 shares of common stock.
Portions of the Registrant's definitive proxy statement for its 1995 Annual
Meeting of Shareholders are incorporated by reference into Part III hereof.
<PAGE>
CASCADE NATURAL GAS CORPORATION
Annual Report to the Securities and Exchange Commission
on Form 10-K
For the Year Ended December 31, 1994
Table of Contents
Page Numbers
------------
PART I
Item 1 - Business 3-10
Item 2 - Properties 11
Item 3 - Legal Proceedings 11
Item 4 - Submission of Matters To a Vote of Security Holders 11
- Executive Officers of the Registrant
PART II
Item 5 - Market for Registrant's Common Equity and Related
Shareholder Matters 14
Item 6 - Selected Financial Data 15-16
Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations 17-19
Item 8 - Financial Statements and Supplementary Data 20-44
Item 9 - Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 45
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 47
Signatures 48
Index to Exhibits 49-52
2
<PAGE>
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, 1994, there were 119,625 residential customers, 22,764
commercial customers, 325 firm industrial customers and 33 traditional
interruptible customers, all of which are classified as core customers. In
addition, there were 92 non-core customers. In 1994, the core customers
provided 69% of the operating margin (down from 73% in 1993) while consuming 25%
of the total gas deliveries, down from 31% in 1993. The non-core customers
(including transportation service) provided the remaining operating margin of
31% (up from 27% in 1992) while consuming 75% of the total throughput, up from
69% in 1993.
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 subject to regulatory review to its customers by
means of a periodic purchased gas cost adjustment (PGA) in each state. Gas
price changes occurring between times when PGA rate changes become effective are
deferred for pass through in the next PGA.
The Corporation is also subject to state regulation with respect to
integrated resource planning and has filed its second Integrated Resource Plan
(IRP) 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.
3
<PAGE>
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)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
Gas Distribution Revenue:
Firm:
Residential. . . . . . . . . . . . . . $ 51,354 $ 46,456 $ 37,424 $ 37,260 $ 33,737
Commercial . . . . . . . . . . . . . . 49,718 46,870 38,797 40,092 38,802
Industrial . . . . . . . . . . . . . . 11,959 10,931 8,715 8,343 8,403
Interruptible:
Commercial . . . . . . . . . . . . . . 3,705 2,954 2,927 3,068 3,158
Industrial . . . . . . . . . . . . . . 2,008 1,845 1,877 2,212 2,888
Non-core. . . . . . . . . . . . . . . . 66,597 70,923 56,149 58,535 67,974
-------- -------- -------- -------- --------
Total gas sales revenue . . . . . . . 185,341 179,979 145,889 149,510 154,962
Transportation revenue. . . . . . . . . 6,871 7,087 6,423 4,658 5,381
-------- -------- -------- -------- --------
Total gas distribution revenue . . . . $192,212 $187,066 $152,312 $154,168 $160,343
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Gas Deliveries (thousands of therms):
Firm:
Residential. . . . . . . . . . . . . . 88,342 87,812 71,211 71,661 64,673
Commercial . . . . . . . . . . . . . . 97,750 102,256 85,303 89,873 86,497
Industrial . . . . . . . . . . . . . . 27,214 28,208 22,585 21,984 21,941
Interruptible:
Commercial . . . . . . . . . . . . . . 5,950 4,730 4,608 5,319 5,396
Industrial . . . . . . . . . . . . . . 5,459 5,925 5,944 7,350 10,507
Non-core. . . . . . . . . . . . . . . . 303,569 269,483 255,707 277,716 301,983
-------- -------- -------- -------- --------
Total sales. . . . . . . . . . . . . . 528,284 498,414 445,358 473,903 490,997
Transportation deliveries . . . . . . . 377,435 240,448 159,779 84,918 112,588
-------- -------- -------- -------- --------
Total deliveries . . . . . . . . . . . 905,719 738,862 605,137 558,821 603,585
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Customers (monthly averages):
Firm:
Residential. . . . . . . . . . . . . . 113,398 104,334 96,621 89,306 82,640
Commercial . . . . . . . . . . . . . . 22,035 21,166 20,266 19,316 18,475
Industrial . . . . . . . . . . . . . . 327 318 308 308 300
Interruptible:
Commercial . . . . . . . . . . . . . . 18 17 17 18 19
Industrial . . . . . . . . . . . . . . 14 13 16 18 19
Non-core. . . . . . . . . . . . . . . . 91 86 80 77 76
-------- -------- -------- -------- --------
Total. . . . . . . . . . . . . . . . . 135,883 125,934 117,308 109,043 101,529
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Year-end totals. . . . . . . . . . . . 142,839 132,668 123,356 114,734 106,933
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
</TABLE>
4
<PAGE>
OPERATING STATISTICS
(dollars in thousands except per therm and per customer data)
(CONTINUED)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
Average Annual Consumption
Per Customer (therms):
Residential . . . . . . . . . . . . . 779 842 737 802 783
Commercial-firm . . . . . . . . . . . 4,436 4,831 4,209 4,653 4,682
Average Annual Revenue
Per Customer:
Residential . . . . . . . . . . . . . $ 453 $ 445 $ 387 $ 417 $ 408
Commercial-firm . . . . . . . . . . . $ 2,256 $ 2,214 $ 1,914 $ 2,076 $ 2,100
Average Rate per Therm:
Firm:
Residential . . . . . . . . . . . . . $0.5813 $0.5290 $0.5255 $0.5199 $0.5217
Commercial. . . . . . . . . . . . . . $0.5086 $0.4584 $0.4548 $0.4461 $0.4486
Industrial. . . . . . . . . . . . . . $0.4394 $0.3875 $0.3859 $0.3795 $0.3830
Interruptible:
Commercial (excluding
facilities charges). . . . . . . . $0.3782 $0.3169 $0.3194 $0.3166 $0.3156
Industrial. . . . . . . . . . . . . . $0.3678 $0.3114 $0.3158 $0.3010 $0.2749
Non-core. . . . . . . . . . . . . . . . $0.2194 $0.2632 $0.2196 $0.2108 $0.2251
Transportation. . . . . . . . . . . . . $0.0182 $0.0295 $0.0402 $0.0549 $0.0478
Average Cost per Therm
For Gas Purchased . . . . . . . . . . . $0.2526 $0.2434 $0.2055 $0.1958 $0.1963
Heating Degree Days
System Average (30-year
average 5,675) . . . . . . . . . . . 5,372 6,071 5,075 5,454 5,396
Maximum Day Send Out
(1,000 therms) Including
Transportation. . . . . . . . . . . . 3,936 3,485 2,687 2,567 2,854
Average Daily Send Out
(1,000 therms) Including
Transportation. . . . . . . . . . . . 2,481 2,024 1,653 1,531 1,654
Employees-End of Year. . . . . . . . . . 476 467 466 460 450
</TABLE>
5
<PAGE>
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 connects with the gas fields in
Alberta, Canada at the international border and extends through Washington and
central Oregon into California.
On November 1, 1993, Northwest completed the process, begun in 1988, of
converting its sales function to firm transportation service. Along with the
sales conversion of its remaining sales service from Northwest, the 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. (The Clay Basin inventory will be completely withdrawn by March 31,
1995 according to a schedule dictated by the assignment agreement.)
Presently, baseload requirements for Cascade's core market group are
provided by six major gas supply contracts with various expiration dates from
1996 through 2008 and totaling 865,010 therms per day. Approximately 72% of the
gas supplied pursuant to the contracts is from Canadian sources. The remainder
is domestic. These contracts are supplemented by various service agreements to
cover periods of peak demand including two storage agreements. 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 (WWP), 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 is currently considering an offer from WWP to
extend the primary term of the agreement by three years, as well as considering
alternative resources to meet the same peak period demand. In addition to
withdrawal and inventory capacity, Cascade also maintains a corresponding amount
of firm transportation from the storage facility to the citygate. In addition
to underground storage, Cascade has entered into contracts with two of its major
industrial customers whereby the customer agrees to switch to alternate fuel
allowing Cascade to reduce firm deliveries to that customer. One such peak
shaving agreement entitles Cascade to call upon 150,000 therms per day up to a
seasonal total of 3,000,000 therms. This contract expires on September 30,
2015. The second peak shaving agreement, which expires on September 30, 2014,
entitles Cascade to call up to 500,000 therms per day up to a seasonal total of
3,000,000 therms. Cascade also owns a propane air peak shaving plant with a
daily capacity of 60,000 therms and has liquefied 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 to a
maximum, renewable inventory of 5,622,000 therms.
Cascade maintains a diversified portfolio of natural gas supplies. During
1994, Cascade purchased gas supplies approximately 59.3% from firm gas supply
contracts, 39.3% from 30-day spot market contracts and 1.4% from customer
assigned gas purchase contracts. In addition, 377,435,000 therms of customer
purchased supplies were transported across Cascade facilities.
6
<PAGE>
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 sales 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
2,282,010 therms per day of firm transportation capacity, not including firm
transportation from storage facilities. As part of the Northwest conversion,
the Corporation took direct assignment of 313,350 therms per day of firm PGT
transportation capacity and has contracted for an additional wintertime only
firm capacity on the PGT system in two increments: 74,460 therms per day of
Phase I capacity beginning November 1, 1993, and 36,000 therms per day of
vintage PGT capacity beginning November 1, 1995. At that time, Cascade will
hold peak day totals of 423,810 therms per day on the PGT system.
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 transition 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 system 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
elected to make a one time payment in 1993, thereby discharging all obligations
for 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 additional capacity acquired in 1993
and 1995. Cascade is seeking full recovery of these payments 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 on Northwest's transmission system,
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. PGT has filed its most recent FERC rate
case assuming incremental rate design as its base case but is advocating rolled-
in rate design as its alternative, and preferred, methodology. The additional
74,460 therms per day of wintertime only firm capacity that Cascade obtained in
PGT's 1993 expansion is being billed under an incremental rate design subject to
refund.
7
<PAGE>
COST OF PURCHASED GAS
Following the implementation of Order 636, Cascade's cost of gas depends
primarily on the prices negotiated with producers and brokers, coupled with the
cost of interstate and Canadian pipeline transportation service.
CURTAILMENT PROCEDURES
In previous heating seasons, cold weather has required Cascade to
significantly curtail its interruptible customers. Cascade has not curtailed
any firm customers, except under force majeure provisions. Cascade's tariffs
effective in Washington and Oregon, allow for curtailment of interruptible
services, which are provided at rates lower than for firm services. In the
event of curtailment by Cascade of firm service due to force majeure, Cascade's
tariffs provide that it shall not be liable for damages or otherwise to any
customer for failure to deliver gas curtailed in accordance with the provisions
of the tariffs. The tariffs provide for appropriate adjustment of the monthly
bill of firm customers curtailed by reason of an insufficient supply of gas.
TERRITORY SERVED AND FRANCHISES
The population of communities served by Cascade totaled approximately
724,000 at the end of 1994 compared to 700,000 at the end of 1993, a 3.4%
increase.
Cascade has all the franchises necessary for the distribution of natural
gas in the communities it serves in Washington and Oregon. Under the laws of
those states, incorporated municipalities and counties may grant non-exclusive
franchises for a fixed term of years conferring upon the grantee certain rights
with respect to public streets and highways in the location, construction,
operation, maintenance and removal of gas distribution facilities.
In the opinion of Cascade's management, none of its franchises contain any
restrictions or requirements which are of a materially burdensome nature, and
such franchises are adequate for the conduct of Cascade's present business.
Franchises expire on various dates from 1995 to 2065. Management has not
incurred significant difficulties in renewing franchises when they expire and
does not expect any significant problems in the future.
CUSTOMERS
Residential and commercial customers principally use natural gas for space
heating and water heating. This market is very weather-sensitive. See
"Seasonality," below.
Of its non-core customers, 15 accounted for approximately 26% of Cascade's
total 1994 gas and transportation revenues. Agreements with its principal
industrial customers are for fixed terms of not less than one year and provide
for automatic extension from year to year unless terminated by either party on
30-days' notice. See Note 11 under Notes to Consolidated Financial Statements,
for information regarding revenues from a major customer.
SEASONALITY
Weather is an important factor affecting gas revenues because of the large
number of customers using gas for space heating. In 1994, 66.1% of operating
revenues and 109.9% 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.
8
<PAGE>
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 near parity with respect to electricity furnished
by those utilities for space heating and water heating uses. Through its
wholly-owned subsidiary, Cascade Land Leasing Co., the Corporation provides
loans to customers to finance the purchase and installation of energy efficient
gas appliances.
Historically, the large volume industrial market was very sensitive to
price fluctuations between the comparable cost of natural gas and alternate
fuels, principally residual fuel oil used in boiler applications. However, the
advent of open access transportation and the restructuring of gas supply and
contractual provisions with these customers has improved the Corporation's
competitive position. From December 1991 through January 1992 and again from
December 1992 through May 1994, except for a brief period in June 1993, residual
fuel oil prices were lower than natural gas, but Cascade did not experience any
significant loss of sales to alternate fuels during those periods.
In addition to multiple alternate fuels, the 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.
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.
9
<PAGE>
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. Management is
investigating the possibility of contamination at one site. Based on
information received to date, it is not aware of hazardous substances present
at any of the 12 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 10
under Notes to Consolidated Financial Statements.
CAPITAL EXPENDITURES
Capital expenditures for 1995 are budgeted for $44,497,000 including
$7,172,000 of projects originally budgeted for 1994 but not completed and
carried over to 1995. Including the 1995 budget, the Corporation will have
spent over $140,000,000 in new plant in the four years ending in 1995 compared
to $133,252,000 in the 12-year period from 1980 through 1991. While easement
and right of way work for service to a fourth cogeneration customer was
initiated in 1994, construction of the line to serve the plant was started in
February, 1995 and will be completed in April, 1995. The 1995 budget includes
funds for a fifth cogeneration customer on the Corporation's system. The
contracts for service to the five cogeneration customers are expected to yield
virtually level payments over the 15 to 25 year contract lives. The contracts
provide for demand charges as well as distribution charges which should recover
the capital investment in the facilities and provide a return to shareholders
over their term. With level payments, projected rates of return are low in the
early years and increase significantly over time as the Corporation's investment
is depreciated.
The Corporation is currently forecasting that capital expenditures will
total approximately $110,000,000 to $150,000,000 over the following five years.
NON-UTILITY SUBSIDIARIES
Cascade has four non-utility subsidiaries. These subsidiaries are engaged
in the following businesses, respectively; financing Cascade customers'
purchases of energy-efficient appliances; 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 operations.
PERSONNEL
At December 31, 1994, Cascade had 476 employees. Of the total employees,
217 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.
10
<PAGE>
ITEM 2 - PROPERTIES
At December 31, 1994, Cascade's utility plant investments included
approximately 3,704 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 2,295 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 Item 1 "Business--Environmental".
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
11
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
The Executive Officers of the Corporation, as of March 1, 1995, are as
follows:
<TABLE>
<CAPTION>
Year
Became
Name Office Age Officer
---- ------ --- -------
<S> <C> <C> <C>
W. Brian Matsuyama Chairman of the Board and
Chief Executive Officer 48 1987
Ralph E. Boyd President and Chief
Operating Officer 58 1988
Donald E. Bennett Executive Vice President,
Chief Financial Officer
and Secretary 62 1978
Jon T. Stoltz Senior Vice President -
Planning and Rates 48 1981
O. LeRoy Beaudry Vice President -
Consumer and Public Affairs 56 1981
Calvin R. Steele Vice President -
Data-Processing 55 1991
King C. Oberg Vice President - 54 1993
Gas Supply
Larry E. Anderson Vice President -
Operations 46 1995
J. D. Wessling Vice President -
Finance 51 1995
James E. Haug Treasurer and Chief
Accounting Officer 46 1981
</TABLE>
None of the above officers is related by blood, marriage or adoption to
any other of the above named officers. Except as discussed below, each of
the above named officers has been employed by the 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.
12
<PAGE>
Larry E. Anderson has been employed by the Corporation since May 1, 1974.
He became Chief Engineer on February 1, 1988 and Director, Engineering on
December 1, 1991.
J. D. Wessling was employed by the Corporation on January 6, 1994 as
Director-Finance. From 1989 through 1993, he was chief financial officer for a
retail drug chain based in Phoenix, Arizona. From 1986 to 1989, he was chief
financial officer of a computer distribution company. Prior to that, Mr.
Wessling spent 12 years in the oil and gas industry, seven of which were with
Atlantic Richfield Company where he held various financial positions.
13
<PAGE>
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, 1995, there were approximately 9,171 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.
<TABLE>
<CAPTION>
Market and Dividend Information
Common stock sales price ranges Dividends
------------------------------- ---------
1994 1993 1994 1993
---- ---- ---- ----
Quarter High Low High Low
---- --- ---- ---
<S> <C> <C> <C> <C> <C> <C>
First 18 1/8 15 7/8 17 15 1/2 .23 2/3 .23 1/3
Second 16 3/4 14 17 3/4 16 5/8 .24 .23 2/3
Third 15 13/16 13 1/4 19 1/2 17 1/4 .24 .23 2/3
Fourth 15 1/2 12 3/4 19 3/8 17 .24 .23 2/3
</TABLE>
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, 1995, to holders of record on January 13,
1995. Future dividend action will depend on the earnings and financial
condition of the Corporation and other relevant factors.
14
<PAGE>
ITEM 6 - SELECTED FINANCIAL DATA (dollars in thousands except per share data)
STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Gas sales . . . . . . . . . . . $ 185,341 $ 179,979 $ 145,889 $ 149,510 $ 154,962
Transportation revenue. . . . . 6,871 7,087 6,423 4,658 5,381
Other operating income. . . . . 198 388 154 144 172
--------- --------- --------- --------- ---------
192,410 187,454 152,466 154,312 160,515
Less: Gas purchases . . . . . . 118,083 113,500 90,320 90,903 97,392
Revenue taxes . . . . . . 11,500 11,095 8,997 9,362 9,192
--------- --------- --------- --------- ---------
Operating Margin . . . . . . . . 62,827 62,859 53,149 54,047 53,931
--------- --------- --------- --------- ---------
Cost of Operations:
Operating expenses. . . . . . . 30,882 28,536 26,262 24,630 22,428
Depreciation and amortization . 10,077 9,151 8,388 7,704 7,282
Property and payroll taxes. . . 4,039 3,757 3,516 3,361 3,373
--------- --------- --------- --------- ---------
44,998 41,444 38,166 35,695 33,083
Overrun Penalty Income . . . . . 1,305
--------- ---------- --------- --------- ---------
Earnings from operations . . . . 17,829 21,415 14,983 19,657 20,848
--------- --------- --------- --------- ---------
Nonoperating Expense (Income):
Interest. . . . . . . . . . . . 8,090 7,038 7,478 7,793 8,374
Interest charged to
construction. . . . . . . . (203) (323) (218) (156) (98)
--------- --------- --------- --------- ---------
7,887 6,715 7,260 7,637 8,276
Amortization of debt issuance
expense . . . . . . . . . . 593 562 402 362 373
Other . . . . . . . . . . . . 84 20 (339) (199) (724)
--------- --------- --------- --------- ---------
8,564 7,297 7,323 7,800 7,925
--------- --------- --------- --------- ---------
Earnings Before Income Taxes and
Cumulative Effect of Change in
Accounting Method . . . . . . 9,265 14,118 7,660 11,857 12,923
Income Taxes . . . . . . . . . . 3,505 5,224 2,817 4,206 4,547
--------- --------- --------- --------- ---------
Earnings Before Cumulative
Effect of Change in
Accounting Method . . . . . 5,760 8,894 4,843 7,651 8,376
Cumulative Effect of Change
in Accounting Method . . . . . . 209
--------- --------- --------- --------- ---------
Net Earnings . . . . . . . . . . 5,760 9,103 4,843 7,651 8,376
Preferred Dividends. . . . . . . 558 580 595 148 154
--------- --------- --------- --------- ---------
Net Earnings Available to
Common Shareholders. . . . . . $ 5,202 $ 8,523 $ 4,248 $ 7,503 $ 8,222
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Shares of Common Stock Outstanding:
(thousands)
End of Year . . . . . . . . . . 8,912 8,566 7,614 6,631 6,565
Average . . . . . . . . . . . . 8,707 7,915 6,681 6,587 6,519
Earnings per Common Share:
Before cumulative effect of change
in accounting method. . . . $ 0.60 $ 1.05 $ 0.64 $ 1.14 $ 1.26
Cumulative effect of
change in accounting
method . . . . . . . . . . . . 0.03
--------- --------- --------- --------- ---------
Net Earnings per Common Share. . $ 0.60 $ 1.08 $ 0.64 $ 1.14 $ 1.26
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
15
<PAGE>
SELECTED FINANCIAL DATA (CONTINUED)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
RETAINED EARNINGS:
Beginning of the year . . . . $ 14,076 $ 13,455 $ 15,655 $ 14,142 $ 11,674
Net earnings after preferred
dividends. . . . . . . . . 5,202 8,523 4,248 7,503 8,222
Common dividends paid in cash (8,472) (7,902) (6,448) (5,990) (5,754)
--------- --------- --------- --------- ---------
End of the year . . . . . . . $ 10,806 $ 14,076 $ 13,455 $ 15,655 $ 14,142
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
CAPITAL STRUCTURES:
Common shareholders' equity . $ 87,710 $ 85,702 $ 69,199 $ 57,225 $ 54,931
--------- --------- --------- --------- ---------
Redeemable preferred stocks . $ 7,217 $ 7,528 $ 7,951 $ 8,254 $ 2,444
--------- --------- --------- --------- ---------
Debt:
Long-term debt . . . . . . $ 100,000 $ 87,000 $ 74,677 $ 57,060 $ 60,803
Notes payable. . . . . . . 14,501 13,502 13,000 8,500 1,500
Current maturities of
long-term debt . . . . . 5,000 0 0 3,500 2,500
--------- --------- --------- --------- ---------
. . . . . . . . . . . . $ 119,501 $ 100,502 $ 87,677 $ 69,060 $ 64,803
--------- --------- --------- --------- ---------
Total capital . . . . . . . . $ 214.428 $ 193,732 $ 164,827 $ 134,539 $ 122,178
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
FINANCIAL RATIOS:
Return on common shareholders'
equity . . . . . . . . . . 6.00% 11.00% 6.72% 13.38% 15.42%
Common stock dividend payout ratio 161% 87% 146% 79% 69%
Dividends paid in cash per
common share . . . . . . . $ 0.96 $0.94 $0.93 $0.90 $0.87
Fixed charge coverage (before income
tax deduction):
Times interest earned. . . 2.07 2.86 1.97 2.45 2.48
Times interest and preferred
dividends earned . . . . 1.87 2.55 1.76 2.39 2.41
Book value per year-end share of
common stock . . . . . . . $ 9.84 $ 10.00 $ 9.09 $ 8.63 $ 8.37
UTILITY PLANT:
Utility plant - end of year . $ 333,863 $ 315,297 $ 283,871 $ 249,027 $ 230,769
Accumulated depreciation. . . 127,806 117,925 109,184 100,927 93,824
--------- --------- --------- --------- ---------
Net plant . . . . . . . . . . $ 206,057 $ 197,372 $ 174,687 $ 148,100 $ 136,945
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Construction expenditures . . $ 27,251 $ 32,990 $ 35,335 $ 19,669 $ 16,415
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Total assets. . . . . . . . . $ 272,297 $ 252,690 $ 224,685 $ 191,471 $ 181,080
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
16
<PAGE>
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
1994 VS 1993
Net earnings to common shareholders for the year 1994 were $5,202,000, or
$0.60 per share compared to $8,523,000, or $1.08 per share in 1993. Fourth
quarter net earnings to common shareholders were $4,418,000, or $0.50 per share
compared to $5,005,000, or $0.59 per share in 1993.
The customer base expanded by 7.7%, reaching a new high of 142,839 at
December 31, 1994. However, operating margin was negatively affected by weather.
Temperatures in 1994 were generally warmer than normal and warmer than 1993,
particularly in the important first quarter when the degree days were 7% warmer
than normal. By comparison, the first quarter of 1993 had temperatures 18%
colder than normal. For all of 1994, the Corporation estimates that the warmer
weather negatively impacted margins by over $2,000,000. Operating margins were
further reduced by increased costs of interstate pipeline capacity to serve
Oregon customers. Costs of $1,670,000, incurred prior to December 1994, were
not recovered in rates since such allowance would have resulted in an Oregon
return on equity exceeding a 12.75% earnings test used by the Oregon Public
Utility Commission. Higher costs from December forward are being fully
recovered in current rates.
MARGIN AND VOLUME CHANGES
BETWEEN 1994 AND 1993
<TABLE>
<CAPTION>
MARGIN CONTRIBUTION (THOUSANDS): THERMS DELIVERIES (THOUSANDS):
Increase(Decrease) Increase(Decrease)
----------------------------------- ----------------------------------
Amount Percent Amount Percent
<S> <C> <C> <C> <C>
Core $(2,463) (5.4)% (4,216) (1.8)%
Non-Core 2,431 14.2 % 171,073 33.5 %
------- ------ ------- ------
Total $ (32) (0.1)% 166,857 22.6 %
------- ------ ------- ------
------- ------ ------- ------
</TABLE>
In the industrial non-core market, deliveries were up substantially and
margins increased by $2,431,000, primarily as the result of service to a new
cogeneration plant beginning in April, 1994.
Operating expenses were up over 1993 by $2,346,000, or 8.2%. Payroll and
benefits costs account for $1,523,000 of this increase, with the largest factor
being additional payroll cost of $912,000. This upward movement is the result of
general salary and wage increases, the addition of 9 employees as of the end of
the year, and a reduction in payroll expense capitalized resulting from lower
capital expenditures in 1994. Employee medical benefits expense increased 26.1%
over 1993 due to claims experience.
Depreciation and amortization expense, along with property and payroll
taxes, were up a total of $1,208,000, or 9.4%, primarily because of increases in
plant and equipment.
Interest expense increased $1,172,000 due to an increase of $16,700,000 in
the average amount of debt outstanding. Other expense includes charges of
$700,000 for revaluation of certain non-operating assets. These "other" charges
along with the unusual transmission capacity charges, negatively affected 1994
earnings $1,546,000, or $0.18 per share.
17
<PAGE>
RESULTS OF OPERATIONS
1993 VS 1992
The continuing strong customer growth coupled with reasonably normal
weather (1.4% 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.
<TABLE>
<CAPTION>
MARGIN AND VOLUME CHANGES
BETWEEN 1993 AND 1992
MARGIN CONTRIBUTION (THOUSANDS): THERMS DELIVERIES (THOUSANDS):
Increase(Decrease) Increase(Decrease)
------------------------------- --------------------------------
Amount Percent Amount Percent
<S> <C> <C> <C> <C>
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%
------- ----- ------- -----
------- ----- ------- -----
</TABLE>
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 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, reflected 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.
18
<PAGE>
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 reflected 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 affect 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.
LIQUIDITY AND CAPITAL RESOURCES
The seasonal nature of the Corporation's business creates short-term cash
requirements to finance customer accounts receivable and construction
expenditures. To provide working capital for these 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. Long-term debt requirements are met
primarily through the issuance of Medium-Term Notes of which there were
$100,000,000 outstanding at the end of 1994 and $50,000,000 registered under the
Securities Act of 1933 and available for issuance.
After preferred and common dividends and preferred redemptions totaling
$8,463,000, there was $4,388,000 of cash flow from year to year operations. This
amount, and proceeds of $4,400,000 from common stock issued to participants in
the Corporation's Dividend Reinvestment Plan and 401(k) Plan along with debt,
were used primarily to fund capital expenditures of $27,251,000.
The Corporation has a capital budget for 1995 of $44,497,000 which will be
funded initially with operating cash flow, secondly from the lines of credit
described above and from the available Medium-Term Notes. The capital budget
includes $7,172,000 of projects initially approved in 1994 but not completed and
therefore carried over to 1995.
EFFECTS OF INFLATION
Changing prices have had a minimal impact on the Company's operating margins.
The effects of price changes in purchased gas costs and the cost of transporting
gas to the Company's system are, for the most part, passed on to customers in
accordance with regulatory policy. Inflationary increases in wages and other
operating expenses are generally recognized by the regulatory agencies in their
rate decisions in general rate filings.
19
<PAGE>
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 21
Consolidated Financial Statements:
Statements of Net Earnings Available to Common
Shareholders for the Years ended
December 31, 1994, 1993 and 1992 22-23
Balance Sheets as of December 31, 1994 and 1993 24-25
Statements of Common Shareholders' Equity for the
Years ended December 31, 1994, 1993 and 1992 26-27
Statements of Cash Flows for the Years ended
December 31, 1994, 1993 and 1992 28-29
Notes to Consolidated Financial Statements for the three
years ended December 31, 1994 30
Independent Auditors' Report on Financial
Statement Schedule 43
Financial Statement Schedules:
Schedule II - Valuation and Qualifying Accounts 44
20
<PAGE>
SCHEDULE II
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
-------- -------- --------------------------- -------- --------
Additions
---------
Balance at Charged to Charged to Balance at
Beginning Costs and Other Deductions End of
Description of Period Expenses Accounts (Note) Period
-------------------------------- ---------- ---------- -------- --------- ---------
<S> <C> <C> <C> <C> <C>
Allowance for Doubtful Accounts:
Year ended:
December 31, 1992 $ 384 249 234 $ 399
-------- --- --- ------
December 31, 1993 $ 399 279 188 $ 490
-------- --- --- ------
December 31, 1994 $ 490 340 369 $ 461
-------- --- --- ------
Note: Accounts receivable written off, net of recoveries
Valuation Reserve - Notes Receivable
December 31, 1994 $ 0 550 577 $1,127
-------- --- --- -------
Valuation Reserve - Investments
December 31, 1994 $ 0 150 $ 150
-------- --- ------
</TABLE>
44
<PAGE>
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
45
<PAGE>
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 1995 Annual Meeting (the 1995 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 executive compensation set forth in the 1995
Proxy Statement, under "Executive Compensation "on pages 7, 8 and 9 and under
"Compensation Committee Interlocks and Insider Participation" on page 9, which
information is incorporated herein by reference.
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 1995 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 1995 Proxy Statement, which information is incorporated herein by
reference.
46
<PAGE>
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 the financial
statement schedule 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, 1994.
47
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CASCADE NATURAL GAS CORPORATION
March 27, 1995 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.
<TABLE>
<S> <C> <C>
Chairman of the Board,
Chief Executive Officer
/s/ W. Brian Matsuyama and Director March 27, 1995
--------------------------------- ------------------
W. Brian Matsuyama (Principal Executive Officer) Date
/s/ Ralph E. Boyd President and March 27, 1995
--------------------------------- ------------------
Ralph E. Boyd Chief Operating Officer Date
Executive Vice President,
Chief Financial Officer,
/s/ Donald E. Bennett Secretary and Director March 27, 1995
--------------------------------- ------------------
Donald E. Bennett (Prinicipal Financial Officer) Date
Treasurer and Chief
/s/ James E. Haug Accounting Officer March 27, 1995
--------------------------------- ------------------
James E. Haug (Prinicipal Accounting Officer) Date
/s/ Carl Burnham, Jr. Director March 27, 1995
--------------------------------- ------------------
Carl Burnham, Jr. Date
/s/ Melvin C. Clapp Director March 27, 1995
--------------------------------- ------------------
Melvin C. Clapp Date
/s/ David A. Ederer Director March 27, 1995
--------------------------------- ------------------
David A. Ederer Date
/s/ Howard L. Hubbard Director March 27, 1995
--------------------------------- ------------------
Howard L. Hubbard Date
/s/ Brooks G. Ragen Director March 27, 1995
--------------------------------- ------------------
Brooks G. Ragen Date
/s/ Andrew V. Smith Director March 27, 1995
--------------------------------- ------------------
Andrew V. Smith Date
/s/ Mary A. Williams Director March 27, 1995
--------------------------------- ------------------
Mary A. Williams Date
</TABLE>
48
<PAGE>
INDEX TO EXHIBITS
Exhibit
No. Description
3.1 Restated Articles of Incorporation of the Registrant as amended
through May 9, 1994. Incorporated by reference to Exhibit 3A to the
Registrant's quarterly report on Form 10-Q dated April 29, 1994.
3.2 Restated Bylaws of the Registrant. Incorporated by reference to
Exhibit 3-(2) to the Registrant's annual report on Form 10-K for the
year ended December 31, 1990.
4.1 Indenture dated as of August 1, 1992, between the Registrant and The
Bank of New York relating to Medium-Term Notes. Incorporated by
reference to Exhibit 4 to the Registrant's current report on Form 8-K
dated August 12, 1992.
4.2 First Supplemental Indenture dated as of October 25, 1993, between the
Registrant and The Bank of New York relating to Medium-Term Notes.
Incorporated by reference to Exhibit 4 to the Registrant's quarterly
report on Form 10-Q for the quarter ended June 30, 1993.
4.3 Rights Agreement dated as of March 19, 1993, between the Registrant
and Harris Trust and Savings Bank. Incorporated by reference to
Exhibit 2 to the Registrant's registration statement on Form 8-A dated
April 21, 1993.
4.4 Amendment to Rights Agreement dated June 15, 1993, between the
Registrant and The Bank of New York. Incorporated by reference to
Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the
quarter ended June 30, 1993.
10.1 This number not used.
10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1)
dated January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.2 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1993 (1993 Form 10-K)
10.3 Service agreement (assigned Storage Gas Service under Rate Schedule
SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation
and the Registrant. Incorporated by reference to Exhibit 10.3 to the
Registrant's 1993 Form 10-K.
10.4 Service Agreement (Liquefaction - Storage Gas Service under Rate
Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline
Corporation and the Registrant. Incorporated by reference to Exhibit
10.4 to the Registrant's 1993 Form 10-K.
10.5 Gas Purchase Agreement dated November 1, 1990, between Mobil Oil
Canada and the Registrant. Incorporated by reference to Exhibit 10-6
to the 1991 Form 10-K.
10.6 Amendment to Gas Purchase Agreement dated August 30, 1991, between
Mobil Oil Canada and the Registrant. Incorporated by reference to
Exhibit 10(h)(2) to the Registrant's registration statement on Form S-
2, No. 33-52672 (the 1992 Form S-2).
49
<PAGE>
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. Incorporated by reference to Exhibit 10.10
to the Registrant's 1993 Form 10-K.
10.11 Agreement for Sale and Purchase of Gas dated November 1, 1993, as
amended by Letter Amendment dated December 8, 1993, between Mobil
Natural Gas, Inc., and the Registrant. Incorporated by reference to
Exhibit 10.11 to the Registrant's 1993 Form 10-K.
10.12 Replacement Firm Transportation Agreement dated July 31, 1991, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10(1) to the 1992 Form S-2.
10.12.1 Amendments dated August 20, 1992, November 1, 1992, October 20, 1993,
and December 17, 1993, to Replacement Firm Transportation Agreement
dated July 31, 1991, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.12.1 to the
Registrant's 1993 Form 10-K.
10.13 Firm Transportation Service Agreement dated April 25, 1991, between
Pacific Gas Transmission Company and the Registrant (1993 expansion).
Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2.
10.14 Firm Transportation Service Agreement dated October 27, 1993, between
Pacific Gas Transmission Company and the Registrant. Incorporated by
reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K.
10.15 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 dated September 23, 1960, as amended by
Letter Agreement dated August 15, 1989, between Northwest Pipeline
Corporation and West Coast Energy Inc. Incorporated by reference to
Exhibit 10(s) to the 1992 Form S-2.
10.15.1 Interim Pricing Arrangement dated November 4, 1993 between Canadian
Hydrocarbons Marketing, Inc. and the Registrant relating to the
Kingsgate Gas Sales Agreement. Incorporated by reference to Exhibit
10.16.1 to the Registrant's 1993 Form 10-K.
50
<PAGE>
10.16 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.
10.17 Storage Agreement dated July 23, 1990, between Washington Water Power
Company and the Registrant. Incorporated by reference to Exhibit
10(v) to the 1992 Form S-2.
10.18 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.19 to the Registrant's 1993 Form 10-K.
NO DATA
10.19 Service Agreement (Firm Redelivery Transportation Agreement under Rate
Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated
January 12, 1994, between Northwest Pipeline Corporation and the
Registrant. Incorporated by reference to Exhibit 10.20 to the
Registrant's 1993 Form 10-K.
NO DATA
10.20 Service Agreement (Firm Redelivery Transportation Agreement under rate
Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between
Northwest Pipeline Corporation and the Registrant. Incorporated by
reference to Exhibit 10.21 to the Registrant's 1993 Form 10-K.
NO DATA
10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources,
Inc. and the Registrant.
10.22 Amended and restated Natural Gas Sales Agreement dated August 17,
1994, between Westcoast Gas Services, Inc. and Registrant which
replaces and substitutes for the Kingsgate Gas Sales Agreement dated
September 23, 1960.
10.23 Firm Transportation Service Agreement dated November 4, 1994, between
Pacific Gas Transmission and the Registrant, effective November 1,
1995.
10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest
Pipeline Corporation and Registrant.
NO DATA
10.25 Prearranged Permanent Capacity Release of Firm Natural Gas
Transportation Agreements dated November 30, 1993 between Tenaska Gas
Co., Tenaska Washington Partners, L.P. and Registrant.
NO DATA
10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between
Tenaska Gas Co., Tenaska Washington Partners, L.P., and Registrant.
10.27 Agreement for Peaking Gas Service dated November 22, 1991, between
Longview Fibre Company and Registrant.
10.29 1991 Director Stock Award Plan of the Registrant.* Incorporated by
reference to Exhibit 10(n) to the 1992 Form S-2.
10.30 Executive Supplemental Income Retirement Plan of the Registrant and
Supplemental Benefit Trust as amended and restated as of May 1, 1989,
as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by
reference to Exhibit 10(o) to the 1992 Form S-2.
10.31 Employment agreement between the Registrant and W. Brian Matsuyama.*
Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
51
<PAGE>
10.32 Employment agreement between the Registrant and Jon T. Stoltz.*
Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2.
12. 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 LLP to the incorporation of their report
in the Registrant's registration statements.
27. Financial Data Schedule (electronic filing only)
--------------
* Management contract or compensatory plan or arrangement.
52
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors
Cascade Natural Gas Corporation
Seattle, Washington
We have audited the accompanying consolidated balance sheets of Cascade Natural
Gas Corporation and subsidiaries (the Corporation) as of December 31, 1994 and
1993, 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, 1994. These financial statements
are the responsibility of the Corporation's management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Cascade Natural Gas Corporation and
subsidiaries as of December 31, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Seattle, Washington
February 3, 1995
-----
21
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF NET EARNINGS
AVAILABLE TO COMMON SHAREHOLDERS
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(dollars in thousands except per share data)
<S> <C> <C> <C>
OPERATING REVENUES:
Gas sales $ 185,341 $ 179,979 $ 145,889
Transportation revenue 6,871 7,087 6,423
Other operating income 198 388 154
---------- --------- ---------
192,410 187,454 152,466
Less:
Gas purchases 118,083 113,500 90,320
Revenue taxes 11,500 11,095 8,997
---------- --------- ---------
OPERATING MARGIN 62,827 62,859 53,149
---------- --------- ---------
COST OF OPERATIONS:
Operating expenses 30,882 28,536 26,262
Depreciation and amortization 10,077 9,151 8,388
Property and payroll taxes 4,039 3,757 3,516
---------- --------- ---------
44,998 41,444 38,166
---------- --------- ---------
Earnings from operations 17,829 21,415 14,983
---------- --------- ---------
NONOPERATING EXPENSE (INCOME):
Interest 8,090 7,038 7,478
Interest charged to construction (203) (323) (218)
---------- --------- ---------
7,887 6,715 7,260
Amortization of debt issuance expense 593 562 402
Other 84 20 (339)
---------- --------- ---------
8,564 7,297 7,323
---------- --------- ---------
EARNINGS BEFORE INCOME TAXES AND
CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING METHOD 9,265 14,118 7,660
INCOME TAXES 3,505 5,224 2,817
---------- --------- ---------
EARNINGS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
METHOD, CARRIED FORWARD 5,760 8,894 4,843
</TABLE>
See notes to consolidated financial statements.
-----
22
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF NET EARNINGS
AVAILABLE TO COMMON SHAREHOLDERS (CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(dollars in thousands except per share data)
<S> <C> <C> <C>
EARNINGS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
METHOD, BROUGHT FORWARD $ 5,760 $ 8,894 $ 4,843
Cumulative effect of change in
accounting method (Note 7) - 209 -
---------- --------- ----------
NET EARNINGS 5,760 9,103 4,843
PREFERRED DIVIDENDS 558 580 595
---------- --------- ----------
NET EARNINGS AVAILABLE TO COMMON
SHAREHOLDERS $ 5,202 $ 8,523 $ 4,248
---------- --------- ----------
---------- --------- ----------
EARNINGS PER COMMON SHARE:
Before cumulative effect of
change in accounting method $ 0.60 $ 1.05 $ 0.64
Cumulative effect of change in
accounting method $ - $ 0.03 -
---------- --------- ----------
NET EARNINGS PER COMMON SHARE $ 0.60 $ 1.08 $ 0.64
---------- --------- ----------
---------- --------- ----------
AVERAGE SHARES OUTSTANDING (Note 4) 8,707,105 7,914,858 6,681,263
---------- --------- ----------
---------- --------- ----------
</TABLE>
See notes to consolidated financial statements.
-----
23
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
December 31
------------------
ASSETS 1994 1993
------ ---- ----
(dollars in thousands)
<S> <C> <C>
UTILITY PLANT (Note 2) $ 333,863 $ 310,288
Less accumulated depreciation 127,806 117,925
---------- ----------
206,057 192,363
Construction work in progress 7,872 5,009
---------- ----------
213,929 197,372
---------- ----------
OTHER ASSETS:
Investments 919 1,149
Notes receivable, less current maturities 2,915 3,508
---------- ----------
3,834 4,657
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 3,949 3,138
Securities available for sale 1,466 757
Accounts receivable, less allowance of
$461 and $490 for doubtful accounts 28,885 26,539
Current maturities of notes receivable 988 1,331
Materials, supplies, and inventories 5,583 6,416
Prepaid expenses and other assets 1,653 444
---------- ----------
42,524 38,625
---------- ----------
DEFERRED CHARGES 12,010 12,036
---------- ----------
TOTAL $ 272,297 $ 252,690
---------- ----------
---------- ----------
</TABLE>
-----
24
<PAGE>
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
December 31
COMMON SHAREHOLDERS' EQUITY, -----------------
PREFERRED STOCKS AND LIABILITIES 1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
COMMON SHAREHOLDERS' EQUITY:
Common stock, par value $1 per share
(Note 4) - Authorized,
15,000,000 shares; issued and
outstanding, 8,911,661 and
8,566,374 shares $ 8,912 $ 8,566
Additional paid-in capital 67,992 63,060
Retained earnings (Note 6) 10,806 14,076
--------- --------
87,710 85,702
--------- --------
REDEEMABLE PREFERRED STOCKS, aggregate
redemption amount of $7,499 and
$7,826 (Note 3) 7,217 7,528
--------- --------
LONG-TERM DEBT (Note 6) 100,000 87,000
--------- --------
CURRENT LIABILITIES:
Notes payable (Note 5) 14,501 13,502
Accounts payable 18,366 22,362
Property, payroll, and excise taxes 4,541 3,960
Dividends and interest payable 4,202 3,665
Other current liabilities 1,620 2,395
Current maturities of long-term debt (Note 6) 5,000 -
--------- --------
48,230 45,884
--------- --------
DEFERRED CREDITS:
Gas cost changes 4,407 3,568
Income taxes (Note 7) 15,382 13,708
Investment tax credits 3,472 3,747
Other 5,879 5,553
--------- --------
29,140 26,576
--------- --------
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10) - -
--------- --------
TOTAL $ 272,297 $ 252,690
--------- --------
--------- --------
</TABLE>
-----
25
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON
SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common stock
------------ Additional
paid-in Retained
Shares Par value capital earnings
------ --------- ---------- --------
(dollars in thousands)
<S> <C> <C> <C> <C>
BALANCE, January 1, 1992 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 plan 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 plan 800 1 19
Dividend reinvestment plan 37,992 38 939
Three-for-two stock split 2,854,656 2,854 (2,865)
Redemption of preferred stock (32)
Cash dividends:
Common stock, $.94 per share (7,902)
Preferred stock, Senior, $.55 per share (109)
7.85% cumulative preferred stock, $7.85
per share (471)
Net earnings 9,103
--------- -------- --------- --------
BALANCE, December 31, 1993, CARRIED FORWARD 8,566,374 8,566 63,060 14,076
</TABLE>
See notes to consolidated financial statements.
-----
26
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON
SHAREHOLDERS' EQUITY (CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common stock Additional
------------ paid-in Retained
Shares Par value capital earnings
------ --------- ---------- --------
(dollars in thousands)
<S> <C> <C> <C> <C>
BALANCE, December 31, 1993, BROUGHT FORWARD 8,566,374 $ 8,566 $ 63,060 $ 14,076
Common stock issued:
Employee Savings Plan and Retirement
Trust (401(k)) 48,959 49 690
Director stock award plan 1,200 1 18
Dividend reinvestment plan 295,128 296 4,222
Redemption of preferred stock 2
Cash dividends:
Common stock, $.96 per share (8,472)
Preferred stock, Senior, $.55 per share (87)
7.85% cumulative preferred stock,
$7.85 per share (471)
Net earnings 5,760
--------- -------- --------- --------
BALANCE, December 31, 1994 8,911,661 $ 8,912 $ 67,992 $ 10,806
--------- -------- --------- --------
--------- -------- --------- --------
</TABLE>
See notes to consolidated financial statements.
-----
27
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net earnings $ 5,760 $ 9,103 $ 4,843
Adjustments to reconcile net
earnings to net cash
provided by operating
activities:
Depreciation 11,239 10,268 9,342
Write-down of assets 700 349 -
Amortization of gas cost changes (3,361) (10,119) (3,070)
Increase in deferred income
taxes 1,674 758 1,976
Cumulative effect of change in
accounting method - (209) -
Decrease in deferred investment
tax credits (275) (266) (274)
Cash provided (used) by changes
in operating assets and
liabilities:
Accounts receivable (2,346) (2,099) (3,515)
Income taxes (476) 98 268
Inventories 34 (601) (244)
Gas cost changes 4,200 (482) (366)
Deferred items 131 490 613
Accounts payable and accrued
expenses (3,661) 6,563 3,918
Prepaid expenses and other assets (725) 138 125
Other (43) (31) 392
-------- -------- --------
Net cash provided by operating
activities 12,851 13,960 14,008
-------- -------- --------
INVESTING ACTIVITIES:
Capital expenditures (27,251) (32,990) (35,335)
New consumer loans (1,393) (2,352) (3,265)
Receipts on consumer loans 2,580 3,533 3,994
Purchase of securities available
for sale (1,502) (747) -
Proceeds from securities available
for sale 752 - -
-------- -------- --------
Net cash used by investing
activities (26,814) (32,556) (34,606)
--------- --------- --------
FINANCING ACTIVITIES:
Issuance of common stock 4,400 14,937 13,380
Redemption of preferred stock (309) (455) (315)
Proceeds from long-term debt, net 17,838 33,686 47,551
Repayment of long-term debt - (22,761) (37,414)
Proceeds from notes payable, net 999 501 4,500
Dividends paid (8,154) (7,506) (6,237)
-------- -------- --------
Net cash provided by financing
activities 14,774 18,402 21,465
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS, CARRIED FORWARD 811 (194) 867
</TABLE>
See notes to consolidated financial statements.
-----
28
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS, BROUGHT FORWARD $ 811 $ (194) $ 867
CASH AND CASH EQUIVALENTS:
Beginning of year 3,138 3,332 2,465
-------- -------- -------
End of year $ 3,949 $ 3,138 $ 3,332
-------- -------- -------
-------- -------- -------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amounts capitalized) $ 7,381 $ 6,744 $ 6,058
Income taxes $ 2,567 $ 2,598 $ 1,050
</TABLE>
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES:
In July 1994, the Corporation sold all of the capital stock of Metrology One,
Inc. and Fibre Graphics, Inc. A note receivable valued at $825,000 was acquired
in exchange for the assets sold.
See notes to consolidated financial statements.
-----
29
<PAGE>
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
-------------------------------------------------------------------------------
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.; and CGC Resources, Inc. The consolidated financial statements also
include the accounts of Fibre Graphics, Inc. and Metrology One, Inc.
through the date of sale of those subsidiaries on July 15, 1994. 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 estimated net realizable value.
NOTES RECEIVABLE: Notes receivable include loans made to customers for the
purchase of energy efficient appliances, which are generally the security
for the loan. Loans are made for a term of five years at interest rates
varying from 6.5% to 12%.
SECURITIES AVAILABLE FOR SALE: Securities available for sale consist of
municipal bonds, at market value, which approximates cost.
MATERIALS, SUPPLIES, AND INVENTORIES: Materials and supplies for
construction and maintenance are recorded at cost. Inventories of gas are
stated at the lower of average cost or market.
DEFERRED CHARGES: Deferred charges consist primarily of debt issuance
costs, intangible assets related to minimum liability accruals on pension
obligations (Note 8), and deferrals of postretirement health care expenses
(Note 8). 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.
-----
30
<PAGE>
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.
GAS COST CHANGES: Gas cost changes consist primarily of the effects of net
decreases in purchased gas costs which have not yet been reflected in rates
charged to customers. The effects of changes that are not tracked on a
concurrent basis are deferred and amortized over a future period through a
temporary rate change schedule. Amortization is subject to the approval of
the regulatory agencies. Periods 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 (Note 7). This
procedure has been accepted by the WUTC and the OPUC.
It is expected that any future increases in federal income taxes resulting
from the reversal of accelerated depreciation on additions to utility plant
in 1980 and prior will be allowed in future rate determinations.
INVESTMENT TAX CREDITS: Investment tax credits were deferred and are
amortized over the life of the property giving rise to the credit.
STATEMENTS OF CASH FLOWS: For purposes of the statements of cash flows,
the Corporation considers all liquid investments with a purchased maturity
of approximately three months or less to be cash equivalents.
RECLASSIFICATIONS: Certain reclassifications have been made in the 1993
financial statements to conform to the classifications used in 1994.
NOTE 2: UTILITY PLANT
Utility plant consists of the following components at December 31:
<TABLE>
1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
Distribution plant $ 284,305 $ 261,994
Transmission plant 14,086 14,086
Production plant 1,053 1,053
General plant 28,994 27,846
Intangible plant 212 212
Nondepreciable plant 5,213 5,097
---------- ----------
$ 333,863 $ 310,288
---------- ----------
</TABLE>
-----
31
<PAGE>
NOTE 3: REDEEMABLE PREFERRED STOCKS
<TABLE>
<CAPTION>
1994 1993
---- ----
Shares Amount Shares Amount
------ ------ ------ ------
(dollars in thousands)
<S> <C> <C> <C> <C>
7.85% cumulative, $1.00 par value 60,000 $ 6,000 60,000 $ 6,000
$.55 cumulative Senior, Series A, B,
and C, without par value:
Beginning of year 167,676 1,528 213,157 1,951
Shares retired 32,249 311 45,481 423
------- ------- ------- -------
Authorized, issued, and outstanding
at end of year 195,427 $ 7,217 227,676 $ 7,528
------- ------- ------- -------
</TABLE>
The Senior preferred stock is subject to mandatory redemption as follows:
<TABLE>
Shares Amount
------ ------
(dollars in thousands)
<S> <C> <C>
1995 38,777 $ 388
1996 25,000 250
1997 25,000 250
1998 25,000 250
1999 14,500 145
</TABLE>
The shares may be purchased on the open market, or redeemed at $10 per share
plus accrued dividends. Redemption in excess of the required number of shares
of preferred stock can be made only if all cumulative dividends on preferred
stock have been paid. The 7.85% cumulative preferred stock may not be redeemed
until maturity on November 1, 1999.
NOTE 4: COMMON STOCK
At December 31, 1994, shares of common stock are reserved for issuance as
follows:
<TABLE>
Number Purchase or contribution
of shares price per share
--------- ---------------
<S> <C> <C>
Employee Savings Plan and Retirement Market closing price of common stock
Trust (401(k) plan) 31,317 immediately prior to purchase by Trustee.
Dividend reinvestment plan 528,834 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 10,800 Market closing price of common stock on the
date of the Corporation's annual meeting.
-------
570,951
-------
</TABLE>
-----
32
<PAGE>
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 5: NOTES PAYABLE
At December 31, 1994, 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 1995, 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 $10,501,000 was outstanding at December 31,
1994. In addition, the Corporation has uncommitted lines of credit available of
$10,000,000 each from three banks, of which $4,000,000 was outstanding at
December 31, 1994.
The average daily amount outstanding under these arrangements during 1994 was
approximately $15,217,000 with a maximum month end borrowing of $23,941,000.
The effective weighted average interest rate (excluding commitment fees) based
upon daily amounts outstanding was 4.87% in 1994 and 3.66% in 1993.
NOTE 6: LONG-TERM DEBT
<TABLE>
<CAPTION>
Long-term debt consists of the following:
1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
9.46% promissory note due 1995 $ 5,000 $ 5,000
Medium-term notes:
5.77% due 1998 5,000 5,000
5.78% due 1998 5,000 5,000
7.18% due 2004 4,000 4,000
7.32% due 2004 22,000 22,000
8.38% due 2005 5,000 -
8.35% due 2005 5,000 -
8.50% due 2006 8,000 -
8.06% due 2012 14,000 14,000
8.10% due 2012 5,000 5,000
8.11% due 2012 3,000 3,000
7.95% due 2013 4,000 4,000
8.01% due 2013 10,000 10,000
7.95% due 2013 10,000 10,000
-------- --------
105,000 87,000
Less current maturities 5,000 -
-------- --------
$100,000 $ 87,000
-------- --------
-------- --------
</TABLE>
None of the long-term debt includes sinking fund requirements.
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 $24,188,000 is available for
payment of dividends as of December 31, 1994.
-----
33
<PAGE>
During 1992 and 1994, the Corporation entered into three interest rate swap
arrangements, with scheduled expiration dates in 1994, 1995, and 1996. These
arrangements effectively converted $25,000,000 of fixed rate debt instruments
into variable rate obligations. Under the terms of these arrangements, the
Corporation made payments at a LIBOR-based floating rate, and received payments
at a fixed rate. The net interest paid or received is included in interest
expense. During 1994, these arrangements were terminated. The settlement
amount, which was not material, was charged to prepaid expenses, and is being
amortized to interest expense over the original terms of the swap arrangements.
NOTE 7: 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.
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.
The provision for income tax expense consists of the following:
<TABLE>
1994 1993 1992
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
Current tax expense $2,120 $3,443 $ 451
Alternative minimum tax (credit carryforward) - (665) 665
Deferred tax expense 1,660 2,668 1,975
Change in tax rates - 44 -
Amortization of deferred investment tax credits (275) (266) (274)
------- ------- -------
$3,505 $5,224 $2,817
------- ------- -------
</TABLE>
During the third quarter of 1993, the Revenue Reconciliation Act of 1993 was
enacted. This Act increased the maximum federal income tax rate applicable to
corporations from 34% to 35%. The provision for deferred income taxes included
a charge of $44,000 ($.01 per share) in 1993 as a result of recalculating
certain deferred tax balances at the new tax rate. A reconciliation between
income taxes calculated at the statutory federal tax rate and income taxes
reflected in the financial statements is as follows:
-----
34
<PAGE>
<TABLE>
1994 1993 1992
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
Statutory federal income tax rate 35 % 35 % 34 %
Income tax calculated at statutory federal rate $3,243 $4,941 $2,604
Increase (decrease) resulting from:
State income tax, net of federal tax benefit 80 106 15
Differences between book and tax depreciation 468 441 513
Amortization of investment tax credits (275) (266) (274)
Other (11) 2 (41)
-------- ------- -------
$3,505 $5,224 $2,817
-------- ------- -------
-------- ------- -------
</TABLE>
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. The tax effects of
significant items comprising the Corporation's net deferred tax liability are as
follows:
<TABLE>
1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
Deferred tax liabilities:
Differences between book and tax basis of property $13,082 $ 11,383
Debt refinancing costs 2,505 2,695
Retirement benefit obligations 829 410
Other 77 26
-------- --------
16,493 14,514
-------- --------
Deferred tax assets:
Valuation reserves 264 -
Retirement benefit obligations 477 450
Provision for doubtful accounts 172 175
Other 198 181
-------- --------
1,111 806
-------- --------
Net deferred tax liability $ 15,382 $ 13,708
-------- --------
</TABLE>
NOTE 8: 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.
-----
35
<PAGE>
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:
<TABLE>
<CAPTION>
Supplemental
Pension plan retirement plan
------------ ---------------
1994 1993 1994 1993
---- ---- ---- ----
(dollars in thousands)
<S> <C> <C> <C> <C>
Actuarial present value of accumulated
benefit obligations:
Vested $ 12,666 $ 21,579 $ 2,310 $ 2,285
Nonvested 137 239 144 138
-------- -------- -------- --------
$ 12,803 $ 21,818 $ 2,454 $ 2,423
-------- -------- -------- --------
-------- -------- -------- --------
Projected benefit obligation for services
rendered to date $(15,590) $(25,823) $ (3,327) $ (3,130)
Plan assets, at fair value, primarily common
stocks, corporate bonds, and life
insurance policies 13,842 21,076 2,387 2,079
-------- -------- -------- --------
Projected benefit obligation in excess of
plan assets (1,748) (4,747) (940) (1,051)
Unrecognized amounts:
Prior service cost 2,316 2,561 - -
Loss (gain) from past experience different
from that assumed 28 2,446 582 523
Net transition obligation 27 33 1,203 1,303
Adjustment to recognize minimum liability - (1,035) (912) (1,119)
-------- -------- -------- --------
Prepaid (accrued) pension cost $ 623 $ (742) $ (67) $ (344)
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
Net pension cost for both plans included the following components:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
(dollars in thousands)
<S> <C> <C> <C>
Service cost of benefits earned during the period $ 1,271 $ 1,113 $ 920
Interest cost on projected benefit obligation 2,044 1,900 1,625
Actual return on plan assets (1,101) (1,485) (1,234)
Deferral of unrecognized loss (gain) and amortization, net (524) 82 (130)
Amount recognized due to settlement 16 - -
------- ------- -------
$ 1,706 $ 1,610 $ 1,181
------- ------- -------
------- ------- -------
</TABLE>
During 1994, a portion of the pension plan obligation was settled by the
purchase, from plan assets, of annuities for substantially all existing
retirees. This resulted in a decrease of $8,297,000 in the projected benefit
obligation.
-----
36
<PAGE>
The actuarial present value of accumulated plan benefits for both plans at
December 31, 1994, reflect increases in the discount rate. This change
decreased the projected benefit obligation of the pension plan and supplemental
retirement plan by $4,462,000 and $220,000, respectively.
The following assumptions were used to determine the projected benefit
obligation and expected return on assets at December 31:
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Pension plan:
Discount rate:
Nonretired lives 8.75% 7.50% 8.50%
Retired lives 8.75 6.00 6.00
Long-term rate of return on plan assets 8.50 8.50 8.50
Rate of increase in future compensation
levels 5.00 5.00 6.00
Supplemental retirement plan:
Discount rate 8.75 7.50 8.50
Long-term rate of return on plan assets 8.50 8.50 8.50
Rate of increase in future compensation
levels 5.00 5.00 6.00
</TABLE>
------------------------------------------
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
$474,000, $370,000, and $217,000 for 1994, 1993, and 1992, 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 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) under SFAS No.
106 exceeded payment of these benefits by $1,892,000 and $1,938,000 in 1994 and
1993, respectively. Of these incremental amounts, $1,493,000 and $1,523,000 are
subject to the jurisdiction of the WUTC. As allowed by the policy of the WUTC,
these amounts have been deferred, and included in deferred charges. Management
believes that these and prospective deferral amounts will be recovered in the
future through rates charged to customers. The remainder of the amount is
subject to the jurisdiction of the OPUC which does not permit deferral of the
incremental expense.
-----
37
<PAGE>
The Corporation's health care plan provides benefits for its retired employees
hired prior to June 1, 1992, and their eligible dependents. In 1992, the
Corporation recognized $239,000 as an expense for postretirement health care
benefits. Net postretirement health care benefit costs for 1994 and 1993
consisted of the following components:
<TABLE>
<CAPTION>
1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
Service cost $ 523 $ 510
Net interest cost 1,151 1,105
Actual return on plan assets 12 -
Net amortization and deferral 551 657
------- -------
$ 2,237 $ 2,272
------- -------
------- -------
</TABLE>
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:
<TABLE>
<CAPTION>
1994 1993
---- ----
(dollars in thousands)
<S> <C> <C>
Accumulated postretirement benefit obligation (APBO):
Retirees $ 3,814 $ 3,722
Fully eligible active plan participants 4,797 5,611
Other active plan participants 5,571 7,807
-------- --------
14,182 17,140
Plan assets, at fair value, primarily common
stocks and corporate bonds 2,498 1,250
-------- --------
Funded status (11,684) (15,890)
Unrecognized transition obligation 11,826 12,483
Unrecognized (gain) loss (1,462) 2,719
--------- ---------
Accrued postretirement benefit cost $ (1,320) $ (688)
--------- ---------
--------- ---------
</TABLE>
The assumed health care cost trend rate used in measuring the APBO is 11% for
1995, trending down to 6% at 2005. At January 1, 1994, the census and per
capita claims cost assumptions were updated, resulting in an approximate 9%
reduction in the APBO. The assumed discount rate used in determining the APBO
was 8.75% at December 31, 1994, and 7.5% at December 31, 1993. The effect of
the increase in the discount rate was a decrease of approximately 9% in the APBO
at December 31, 1994. A one percentage point increase in the assumed health
care cost trend rate for each year would increase the APBO by approximately 16%
and the service and interest cost components of net postretirement health care
cost by approximately 20%.
NOTE 9: 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.
-----
38
<PAGE>
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 1996, require that the
Corporation take 100% of all tendered gas volumes during the remaining life of
the agreements. These requirements are for 91,250,000 therms in 1995 and
76,000,000 therms in 1996. 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 9,841,650
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.
<TABLE>
<CAPTION>
Storage
Firm and
gas peaking
supply Transportation service Total
------ -------------- ------- -----
(dollars in thousands)
<S> <C> <C> <C> <C>
1995 $ 40,719 $ 24,849 $ 5,781 $ 71,349
1996 33,089 24,999 4,127 62,215
1997 16,794 24,999 4,127 45,920
1998 16,406 24,999 4,127 45,532
1999 14,475 24,999 4,127 43,601
Thereafter 69,610 364,595 43,801 478,006
--------- --------- --------- ---------
$ 191,093 $ 489,440 $ 66,090 $ 746,623
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
Purchases under these contracts for 1992, 1993, and 1994, including commodity
purchases, as well as demand charges have been as follows:
<TABLE>
<CAPTION>
Storage
Firm and
gas peaking
supply Transportation service Total
------ -------------- -------- -----
(dollars in thousands)
<S> <C> <C> <C> <C>
1992 $ 45,812 $ 10,201 $ 3,944 $ 59,957
1993 $ 50,036 $ 18,691 $ 4,179 $ 72,906
1994 $ 54,695 $ 22,751 $ 4,639 $ 82,085
</TABLE>
NOTE 10: 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 $99,000 are adequate to complete the remediation.
-----
39
<PAGE>
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.
NOTE 11: REVENUES FROM MAJOR CUSTOMER
In 1994, one customer accounted for approximately $20,215,000 in gas revenues.
This represents 10.5% of total revenues; however, margins derived from this
customer were less than 3% of total margin. Outstanding accounts receivable
from this customer at December 31, 1994, totalled $2,144,000, which represents
December 1994 consumption. In 1993 and 1992 no one customer accounted for more
than 10% of gas revenues.
NOTE 12: 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 Corpora-
tion could realize in a current market exchange. Thus, the use of different
market assumptions and/or estimation methodologies may have a material effect on
the estimated fair value amounts.
The estimated fair value amounts of financial instruments at December 31 are as
follows:
<TABLE>
<CAPTION>
1994 1993
---- ----
Carrying Estimated Carrying Estimated
amount fair value amount fair value
-------- ---------- -------- ----------
(dollars in thousands)
<S> <C> <C> <C> <C>
Assets:
Cash and cash equivalents $ 3,949 $ 3,949 $ 3,138 $ 3,138
Notes receivable, including current
maturities 3,903 3,955 4,839 4,984
Accounts receivable 28,885 28,885 26,539 26,539
Securities available for sale 1,466 1,466 757 757
Redeemable preferred stock 7,217 6,924 7,528 7,482
Liabilities:
Long-term debt 100,000 93,187 87,000 93,705
Notes payable 14,501 14,501 13,502 13,502
Current maturities of long-term debt 5,000 5,096 - -
</TABLE>
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.
SECURITIES AVAILABLE FOR SALE: Fair values are based on quoted market
prices.
-----
40
<PAGE>
NOTE 13: INTERIM RESULTS OF OPERATIONS (UNAUDITED)
<TABLE>
<CAPTION>
Quarter ended
-------------------------------------------------
March 31, June 30, September 30, December 31,
1994 1994 1994 1994
---- ---- ---- ----
(dollars in thousands except per share data)
<S> <C> <C> <C> <C>
Operating revenues $ 64,746 $ 36,264 $ 28,867 $ 62,533
Gas costs and revenue taxes 44,179 24,863 19,705 40,836
-------- -------- -------- --------
Operating margin 20,567 11,401 9,162 21,697
Cost of operations 11,175 11,393 10,933 11,497
-------- -------- -------- --------
Earnings from operations 9,392 8 (1,771) 10,200
Interest and other, net 1,837 1,873 1,956 2,898
-------- -------- -------- --------
Earnings before income taxes 7,555 (1,865) (3,727) 7,302
Income taxes 2,744 (590) (1,397) 2,748
-------- -------- -------- --------
Net earnings (loss) $ 4,811 $ (1,275) $ (2,330) $ 4,554
-------- -------- -------- --------
-------- -------- -------- --------
Earnings (loss) per share $ 0.54 $ (0.16) $ (0.28) $ 0.50
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
-----
41
<PAGE>
<TABLE>
<CAPTION>
Quarter ended
-------------------------------------------------
March 31, June 30, September 30, December 31,
1994 1994 1994 1994
---- ---- ---- ----
(dollars in thousands except per share data)
<S> <C> <C> <C> <C>
Operating revenues $ 61,729 $ 37,141 $ 29,435 $ 59,149
Gas costs and revenue taxes 38,993 20,637 26,127 38,838
-------- -------- -------- --------
Operating margin 22,736 11,014 8,978 20,311
Cost of operations 10,264 10,440 10,027 10,713
-------- -------- -------- --------
Earnings from operations 12,472 574 (1,229) 9,598
Interest and other, net 2,213 1,682 1,644 1,758
-------- -------- -------- --------
Earnings before income taxes
and cumulative effect of
change in accounting method 10,259 (1,108) (2,873) 7,840
Income taxes 3,704 (272) (903) 2,695
-------- -------- -------- --------
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 ofchange
in accounting method 0.03 - - -
-------- -------- -------- --------
Earnings (loss) per share $ 0.87 $ (0.13) $ (0.25) $ 0.59
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
Earnings (loss) per share have been restated for the effect of the
three for two stock split in December 1993.
-----
42
<PAGE>
INDEPENDENT AUDITORS' 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, 1994 and 1993, and for each of
the three years in the period ended December 31, 1994, and have issued our
report thereon dated February 3, 1995; 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. The financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express an
opinion based on our audits. In our opinion, such financial statement schedule,
when considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information shown therein.
/s/ Deloitte & Touche LLP
Seattle, Washington
February 3, 1995
----
43
<PAGE>
GAS PURCHASE CONTRACT
between
CASCADE NATURAL GAS CORPORATION
as "BUYER"
and
IGI RESOURCES, INC.
as "SELLER"
AS OF
October 1, 1994
<PAGE>
INDEX
Article I Definitions 1
Article II Conditions Precedent 4
Article III Delivery of Gas 6
Article IV Commitments by Seller 7
Article V Quality 7
Article VI Delivery Point(s) and Pressure 8
Article VII Pipeline Transportation 8
Article VIII Quantity 10
Article IX Measurement 13
Article X Price 13
Article XI Payment 14
Article XII Term 17
Article XIII Force Majeure 18
Article XIV Arbitration 24
Article XV Confidentiality 28
Article XVI Taxes 28
Article XVII Off-Peak Sales 29
Article XVIII Supply Assurance 31
Article XIX Regulatory and Transportation
Agreement Compliance 32
Article XX Equal Opportunity Clause 33
Article XXI General Terms 35
<PAGE>
GAS PURCHASE CONTRACT
THIS GAS PURCHASE CONTRACT ("Contract"), made and entered into as of this
1st day of October, 1994, by and between CASCADE NATURAL GAS CORPORATION,
hereinafter referred to as "Buyer" and IGI RESOURCES, INC., hereinafter referred
to as "Seller".
W I T N E S S E T H:
WHEREAS, Seller is engaged in the sale of natural gas in "first sale"
transactions as defined in Section 2(21) of the Natural Gas Policy Act of 1978
and the Regulations of the Federal Energy Regulatory Commission thereunder; and
WHEREAS, Buyer desires to purchase certain volumes of natural gas from
Seller, and Seller desires to sell such gas to Buyer, pursuant to the terms and
conditions contained herein; and
NOW, THEREFORE, in consideration of the mutual agreements, covenants and
conditions contained herein, Seller and Buyer agree as follows:
ARTICLE I
DEFINITIONS:
1.01 For the purpose hereof, the words, phrases, and terms used herein
shall be used in their ordinary meaning unless the Contract clearly indicates
otherwise or unless same is hereinafter defined, in which instance such word,
phrase, or term shall have the meaning clearly attributable to it or as defined
hereinafter below:
a. The abbreviation "AAA" shall mean the American Arbitration
Association or its successor.
-3-
<PAGE>
b. The abbreviation "ANG" shall mean Alberta Natural Gas Company,
Ltd.
c. The phrase "ANG Expansion Facilities" shall mean those pipeline
facilities proposed for construction under National Energy Board Hearing Order
No. GHW-2-91, which were placed in service on November 1, 1993.
d. The abbreviation "BTU" shall mean British Thermal Unit.
e. The term "cubic foot of gas" shall mean the volume of gas con-
tained in one (1) cubic foot of space at a pressure base of fourteen and
seventy-three hundredths (14.73) psia and at a temperature of sixty degrees (60
DEG.) Fahrenheit.
f. The word "day" shall mean a period of twenty-four (24) consecutive
hours as defined by PGT in its currently effective FERC Gas Tariff, as may be
amended from time to time.
g. The phrase "Delivery Point" shall mean the inlet to the PGT
transmission facilities from the ANG transmission facilities near Kingsgate,
British Columbia.
h. The abbreviation "FERC" shall mean the Federal Energy Regulatory
Commission.
i. The word "gas" shall mean natural gas produced from gas wells
and/or gas produced in association with oil (casinghead gas) and/or the residue
gas resulting from processing both gas-well gas and casinghead gas.
j. The term "gross heating value" shall mean the number of BTU's
produced by combustion at constant pressure and constant temperature of an
amount of gas which would occupy one (1) cubic foot at a temperature of sixty
degrees (60 DEG.) Fahrenheit and a pressure of fourteen and seventy-three
hundredths (14.73) psia on an as delivered basis.
k. The abbreviation "MCF" shall mean one thousand (1,000) cubic feet.
-4-
<PAGE>
l. The abbreviation "MMBTU" shall mean one million (1,000,000) BTU's.
m. The word "month" shall mean the period commencing on the first day
of a calendar month and ending on the first day of the next succeeding calendar
month.
n. The abbreviation "NEB" shall mean the National Energy Board of
Canada.
o. The abbreviation "Northwest" shall mean Northwest Pipeline
Corporation.
p. The abbreviation "NOVA" shall mean Nova Corporation of Alberta.
q. The abbreviation "PGT" shall mean Pacific Gas Transmission
Company.
r. The phrase "PGT Expansion Facilities" shall mean those pipeline
facilities proposed for construction under FERC Docket No. CP-89-460, et.al.,
which were placed in service on November 1, 1993.
s. The word "Pipeline" shall mean PGT or any such other interstate,
intrastate or provincial Pipeline acting as a third party transporter of gas, as
may be mutually agreed upon by the parties from time to time.
t. The abbreviation "psia" shall mean pounds per square inch
absolute.
u. The word "well" shall mean any well classified as a gas well or
oil well by the jurisdictional agency or governmental authority having
jurisdiction. Each completion shall be deemed to be a separate well.
v. The word "year" shall mean a period of twelve (12) consecutive
months commencing on the first day of October and ending on the next succeeding
September 30th except for the first year of the Contract which shall begin on
November 1, 1993 and end on September 30, 1994.
-5-
<PAGE>
ARTICLE II
CONDITIONS PRECEDENT:
2.01 The obligations of Seller to deliver and sell and of Buyer to take and
purchase gas hereunder will not arise prior to the satisfaction of each of the
following conditions precedent upon terms and conditions satisfactory to both
Buyer and Seller:
(a) Seller obtaining or causing to be obtained all required approvals
from all Canadian federal and provincial government agencies, departments and
regulatory bodies having jurisdiction, including all necessary permits, orders
and licenses to allow Seller to sell gas to Buyer pursuant to this Contract.
Principally, at the present time, these approvals are an Energy Removal Permit
from the Province of Alberta and an NEB Export Order from the Government of
Canada. The parties recognize that the purchase and sale of gas supply from
Canada subject to short-term provincial Energy Removal Certificates and NEB
Export Orders ("Short Term Regulatory Approvals") currently results in lower
cost than under long term approvals for firm gas supply service. Under long-
term approvals, the NEB requires the Seller to set aside reserves, which may
cause the Seller to charge the Buyer a higher Reservation Fee (as defined in
Article X below). Seller agrees to use reasonable best efforts to obtain
renewal of these authorizations as required to ensure Short Term Regulatory
Approvals over the term hereof. Seller agrees to obtain Short Term Regulatory
Approvals that have been granted for a period of time no less than six months
commencing no later than October 1st of one calendar year and expiring no
earlier than March 31st of the next succeeding calendar year. Not later than
August 15th of each year during term hereof, Seller will confirm to Buyer in
writing that it has secured Short Term Regulatory Approvals for the subsequent
year. In the event that the Buyer does not receive satisfactory assurance that
such Short Term Regulatory
-6-
<PAGE>
Approvals will be received by October 1st of the same year, then Buyer shall
have the right to terminate the Contract and find an alternative supplier. In
the event Seller shall have failed to use reasonable best efforts to obtain
Short Term Regulatory Approvals in a timely manner, Buyer shall be entitled to
pursue available legal remedies against Seller.
(b) Buyer obtaining or causing to be obtained an import authorization
from the United States Department of Energy, Office of Fossil Energy or its
successor to enable gas to be imported by Buyer pursuant to this Contract.
(c) Buyer obtaining, or causing to be obtained, all required
approvals from all United States federal and state government agencies,
departments and regulatory bodies having jurisdiction to allow Buyer to receive,
transport and sell in the United States gas purchased pursuant to this Contract.
(d) Seller and Buyer obtaining all necessary gas transportation
agreements and assignments of such in a form satisfactory to both parties,
including but not limited to, Seller arranging for firm transportation of the
gas on the NOVA expansion pipeline facilities within Alberta; Buyer arranging
for firm transportation of the gas on the ANG Expansion Facilities to the
Delivery Point; and Buyer arranging for firm transportation on the PGT Expansion
Facilities from the Delivery Point to Buyer's interconnection with Northwest, if
applicable, or to Buyer's other city gate location(s).
(e) The completed construction and placing in-service of the PGT
Expansion Facilities and the ANG Expansion Facilities.
2.02 The conditions precedent under Section 2.01 shall be satisfied on or
before November 1, 1993. If they are not so satisfied, either party may by
written notice to the other party cancel this Contract effective one hundred and
eighty (180) days after the date of the notice. Waiver of the
-7-
<PAGE>
satisfaction of any condition precedent may only be by mutual approval of both
parties. If all conditions precedent are satisfied before a notice of
cancellation is given, the right to cancel under this Section 2.02 shall cease.
If the conditions precedent are satisfied after a notice of cancellation is
given, but prior to the effective date of the cancellation, the cancellation
shall not occur and the right to cancel under this Section 2.02 shall cease.
2.03 The parties will cooperate with each other in order to assist each
other in satisfying the conditions precedent under Section 2.01 so that the
delivery of gas may commence hereunder. Each party will use all reasonable
efforts to satisfy the conditions precedent under Section 2.01.
2.04 If the authorizations and orders referred to in Section 2.01 are
granted for a period which is shorter than the term hereof or are reviewable and
subject to recision during the term hereof, then in the event any of them
terminate and a further authorization or order is not granted with effect from
the date of such termination, or in the event the Delivery Point Selling Price
or other consideration payable hereunder is renegotiated or arbitrated and must
be authorized by a governmental authority, then Seller shall have the right to
suspend deliveries hereunder and Buyer shall have the right to suspend
nominations hereunder until such authorization comes into effect. In the event
deliveries or nominations are suspended pursuant to this clause for a period in
excess of sixty (60) days, then no later than five (5) business days subsequent
to the sixtieth (60th) day of such suspension, either party upon thirty (30)
days written notice to the other may terminate this Contract.
ARTICLE III
DELIVERY OF GAS:
3.01 Buyer shall provide Seller with monthly projections of daily gas
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demands five (5) days prior to the start of each month under this Contract.
Buyer shall also make daily nominations for gas deliveries hereunder to Seller,
and Seller agrees to provide such volumes to Buyer at the Delivery Point on a
daily basis under the terms of this Contract. Buyer and Seller shall comply
with the nomination procedures set forth by the Pipeline, and shall have agents
or employees available at reasonable times to receive a notice for change in the
rate of delivery hereunder as may be required from time to time.
ARTICLE IV
COMMITMENTS BY SELLER:
4.01 Seller represents, subject to Section 4.02, that it owns or controls
sufficient gas reserves and deliverability required to sustain the contract
quantity, as defined in Section 8.01 herein, through the term of the Contract.
4.02 The purchase and sale of natural gas under this Contract is to be made
under the provisions of the Natural Gas Policy Act of 1978 ("NGPA") and the
regulations issued by the FERC thereunder. Seller represents that in the event
the gas which is subject to this Contract is subject to the FERC's jurisdiction
under Section 1(b) of the Natural Gas Act, pursuant to the provisions of the
NGPA, Seller has obtained or caused to have been obtained FERC authorization to
commence deliveries of gas in interstate commerce to Buyer hereunder.
ARTICLE V
QUALITY:
5.01 Seller represents that all gas delivered by Seller to Buyer hereunder,
shall meet the Pipeline's specifications as to quality at the Delivery Point as
established from time to time. In the event gas is tendered
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to Buyer, or the Pipeline for the account of Buyer, which fails to meet the
aforementioned quality specifications, Buyer, upon notice to Seller identifying
the deficiency, may refuse to accept delivery of such gas and shall not be
responsible for payment of such gas so refused under this Contract. Further, as
between the Buyer and Seller, any and all claims for damages from the Pipeline
resulting from the delivery of gas that fails to meet the Pipeline's quality
specifications shall be the sole responsibility of the Seller.
ARTICLE VI
DELIVERY POINT(S) AND PRESSURE:
6.01 Seller shall deliver the gas committed hereunder at the Delivery
Point, as defined in ARTICLE I - DEFINITIONS above. Gas will be delivered at a
pressure which is sufficient to effect delivery at said Delivery Point. Title
to and control of all gas delivered hereunder shall pass from Seller to Buyer at
the Delivery Point.
ARTICLE VII
PIPELINE TRANSPORTATION:
7.01 Seller represents that it has secured or will use due diligence to
cause to be secured the requisite firm transportation service on the NOVA
pipeline facilities as may be required for the ultimate delivery of the gas
hereunder to the Delivery Point. Such NOVA firm transportation service shall be
for a quantity sufficient to deliver the contract quantity as defined in
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Section 8.01 hereunder through the term of the Contract.
7.02 Buyer represents that it has secured or will use due diligence to
cause to be secured the requisite firm transportation service on the ANG
Expansion Facilities as may be required for the ultimate delivery of the gas
hereunder to the Delivery Point. Such ANG firm transportation service shall be
for a quantity sufficient to deliver the contract quantity as defined in Section
8.01 hereunder through the term of the Contract.
Unless otherwise mutually agreed to by the parties hereto, Buyer
agrees to assign its ANG firm service agreement to Seller in order for Seller to
more efficiently administer the daily transportation of gas hereunder to the
Delivery Point. At the expiration of the term hereunder or if this Contract
should otherwise terminate for any reason, the assignment of the ANG firm
service agreement from Buyer to Seller shall also terminate coincident with such
expiry or termination and the ANG firm service agreement shall revert back to
Buyer. While the ANG firm service agreement is assigned to Seller, Seller shall
perform any duties or responsibilities thereunder and shall indemnify and hold
Buyer harmless from any failure to do so.
7.03 Buyer represents that it has or will diligently pursue and secure all
requisite firm transportation agreements specifically required for the
transportation of the gas hereunder from the Delivery Point to Buyer's city gate
location(s).
7.04 The rules, guidelines, and policies of the Pipelines actually
transporting gas hereunder to and from the Delivery Point, as amended from time
to time, shall define and set forth, among other things, the manner in which gas
purchased and sold under this Contract is transported. Buyer and Seller
recognize that the receipt and delivery on the Pipelines' facilities of gas
purchased and sold under this Contract shall be subject to the operational
procedures of the Pipelines. Buyer and Seller shall be obligated to use their
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best efforts to avoid imposition of penalties for imbalances under the general
terms and conditions of the Pipelines' currently effective FERC gas tariff, or
other effective tariff. If during any month Buyer or Seller receives an invoice
from the Pipelines which includes an imbalance penalty charge, both parties
shall be obligated to use their best efforts to determine the validity as well
as the cause of such imbalance penalty charge. If the parties determine that
the imbalance penalty charge was imposed as a result of Buyer's actions (which
shall include, but not be limited to, Buyer's failure to accept a daily quantity
of gas equal to Buyer's nomination of its daily volume requirements), then Buyer
shall be solely responsible for such imbalance penalty charge. If the parties
determine that the imbalance penalty charge was imposed as a result of Seller's
actions (which shall include, but not be limited to, Seller's failure to deliver
a daily quantity of gas equal to Buyer's nomination of its daily volume require-
ments), then Seller shall be solely responsible for such imbalance penalty
charge. If the parties cannot determine that the imbalance penalty charge was
imposed due to the sole action of the Buyer or Seller or if it is determined
that the imbalance penalty charge was imposed as a result of common action by
the Buyer and Seller, then the Buyer and Seller shall be responsible for such
imbalance penalty charge in proportion to their responsibility for such charge.
If an imbalance penalty charge is assessed during the duration of an event of
force majeure, the penalty charge shall be borne by the party against whom it is
charged.
ARTICLE VIII
QUANTITY:
8.01 It is expressly agreed that subject to an event of force majeure, as
defined in Article XIII - FORCE MAJEURE herein, and subject to Section 8.02
herein, Seller shall make available to Buyer and Buyer will purchase from
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Seller during the period October 1st through March 31st of each Contract year
hereunder ("Winter Period"), a maximum quantity of gas less than or equal to one
million three hundred fifty five thousand, one hundred and seventy two
(1,355,172) MMBTU except for the first Contract year of the primary term, as
defined in ARTICLE XII - TERM below, in which the first month of the Winter
Period is November 1, 1993, the in-service date of the ANG and PGT Expansion
Facilities. Without the prior written consent of Seller, the Maximum Daily
Quantity ("MDQ") requested by Buyer hereunder shall not exceed seven thousand
four hundred and forty six (7,446) MMBTU per day plus an additional quantity of
gas at the Delivery Point as compressor station fuel, line loss and unaccounted
for gas as specified in PGT's currently effective FERC Gas Tariff, as may be
amended from time to time.
8.02 During the Winter Period of each Contract year through the term of the
Contract hereunder, Buyer agrees to the following minimum take commitments:
October - 50% of the MDQ on a monthly basis.
November - 70% of the MDQ on a monthly basis.
December - 90% of the MDQ on a monthly basis.
January - 90% of the MDQ on a monthly basis.
February - 70% of the MDQ on a monthly basis.
March - 50% of the MDQ on a monthly basis.
In addition, subject to an event of force majeure as defined in
ARTICLE XIII - FORCE MAJEURE herein and the provisions of ARTICLE XVIII - SUPPLY
ASSURANCE herein, Buyer agrees not to purchase other gas supplies accessible
through the ANG Expansion Facilities until the minimum take commitments of this
Section 8.02 have been nominated.
These minimum take commitments may change if mutually agreed to by the
parties hereto as part of each annual price renegotiation.
In the event Buyer is unable to take, for reasons other than an event
of force majeure as defined in Article XIII - FORCE MAJEURE herein, a
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total volume each Winter Period equal to 70% of the MDQ multiplied by the number
of days in the Winter Period, then with a minimum of one hundred twenty (120)
days written notice prior to the start of the next succeeding Contract year,
Seller may elect to reduce the MDQ to the average daily volume actually taken in
the deficient Winter Period times a factor of 1.42857 (1 / 0.7). In the event
of such reduction in the MDQ, Buyer shall remain responsible for the applicable
NOVA Demand Charges associated with the original MDQ. Seller will use all
reasonable efforts to mitigate the NOVA Demand Charges down to the reduced MDQ.
8.03 Buyer shall be obligated to pay for, in accordance with Article X,
PRICE, and Article XI, PAYMENT, all quantities of gas nominated by Buyer and
tendered for delivery by Seller.
8.04 Seller shall provide Buyer notification by telephone of any
reduction or increase in the volumes and/or BTU content of gas to be delivered
hereunder at least forty-eight (48) hours prior to such reduction or increase,
provided such information is available to Seller.
8.05 Buyer shall have the right to temporarily reduce its daily purchase
of gas in whole or in part from Seller hereunder. Should Buyer determine it to
be necessary to reduce purchases in whole or in part under the provisions of
this paragraph, Buyer shall, as soon as practicable after determination of the
necessity for such reduction, notify Seller of Buyer's estimate of the amount
and length of reduction. Buyer agrees to use its reasonable efforts to give
Seller forty-eight (48) hours notice prior to a reduction, subject to Buyer's
discretion to control its operating conditions.
8.06 Notwithstanding the foregoing, Buyer's exercise of its right to
temporarily reduce its daily purchase of gas shall not relieve Buyer of its
purchase obligations under Section 8.02 herein, and any exercise of such right
shall be in a manner consistent with such purchase obligations.
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ARTICLE IX
MEASUREMENT:
9.01 It is understood and agreed to by the parties hereto that measurement
and determination of gross heating value of gas delivered hereunder shall be in
accordance with the terms of any currently effective and applicable transpor-
tation agreement(s) and in compliance with the Pipeline's currently effective
and applicable tariff, policies, and procedures. All statements of volume and
heating value hereunder shall be computed from the Pipeline's measurement and
testing records.
ARTICLE X
PRICE:
10.01 For all gas nominated by Buyer and accepted for delivery from
Seller by PGT, Buyer shall pay Seller a total selling price which shall consist
of the following components:
a. A reservation fee ("Reservation Fee") each month during the term
hereunder equal to [CONFIDENTIAL INFORMATION OMITTED AND FILED
SEPARATELY WITH THE COMMISSION] per MMBTU times the MDQ times the
number of days in the month.
b. A demand charge each month during the term hereunder equal to the
actual monthly toll charges on the NOVA pipeline facilities
("NOVA Demand Charge") associated with the MDQ for firm receipt
and redelivery of gas hereunder to the ANG Expansion Facilities
plus an allowance for firm gathering and processing equal to the
sum of (i) Contract Demand Raw Gas Transmission Service and (ii)
Contract Demand Treatment Service for 0% acid gas as stated in
the currently effective Westcoast Energy Pipeline Tariff, as may
be amended from time to time.
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c. As a result of the assignment pursuant to Section 7.02 hereunder,
a demand charge each month during the Winter Period hereunder
equal to the actual monthly toll charges on the ANG Expansion
Facilities ("ANG Demand Charge") associated with the MDQ for firm
receipt and redelivery of gas hereunder to the Delivery Point.
d. A commodity charge ("Commodity Charge") equal to an agreed to
price at the Delivery Point (the "Delivery Point Selling Price")
less the NOVA Demand Charge and the ANG Demand Charge as
calculated at a one hundred percent (100%) load factor. The
Delivery Point Selling Price shall be stated on Exhibit "A"
attached hereto and incorporated herein by reference, and shall
be negotiated annually pursuant to Section 10.03 herein and shall
be subject to binding arbitration as defined in Article XIV
hereunder.
10.02 Buyer shall pay Seller the charges described under Sections
10.01(a), (b) and (c) herein whether or not any gas is delivered and accepted
hereunder and whether or not Buyer has declared an event of force majeure,
unless the failure to deliver is caused by the fault of the Seller or by a
declaration of an event of force majeure by Seller or a suspension of delivery
pursuant to Section 2.04 herein.
In the event any governmental authority imposes regulated pricing for
gas to be delivered hereunder, Seller may, upon sixty (60) days written notice,
suspend deliveries hereunder and Buyer may suspend nominations hereunder at any
time after the date such regulated pricing becomes effective. If deliveries or
nominations are suspended hereunder for any consecutive sixty (60) day period,
either party may terminate this Contract upon thirty (30) days written notice to
the other subsequent to the end of such 60 day period.
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If rights of suspension are not invoked by either party within one hundred and
eighty (180) days of regulated pricing becoming effective, then the parties
shall be deemed to have agreed to such pricing and this Contract shall be deemed
amended to the extent necessary to impose such regulated pricing, and as amended
shall be deemed ratified by the parties.
10.03 Buyer and Seller agree to meet no later than ninety (90) days
prior to the end of each Contract year hereunder for the purpose of
renegotiating the Delivery Point Selling Price for the next succeeding Contract
year. In the event neither Buyer nor Seller gives its timely written notice of
its intent to renegotiate the Delivery Point Selling Price hereunder for the
next succeeding Contract year at least ninety (90) days prior to the end of the
current Contract year then the Delivery Point Selling Price hereunder for the
next succeeding Contract year shall remain the same as the Delivery Point
Selling Price in effect for the current Contract year.
ARTICLE XI
PAYMENT:
11.01 Buyer shall furnish Seller with a copy of any statement received
from the Pipeline related to the purchase and transportation of quantities of
gas hereunder. On or before the 10th day of each calendar month for all gas
delivered hereunder during the preceding calendar month, Seller shall furnish
Buyer with an invoice showing the quantity of gas delivered by Seller to Buyer.
If the actual volume delivered is not available by the contractual billing date,
billing will be prepared based on Buyer's nominations for the preceding month.
The estimated volume will then be corrected to the actual volume on the
following month's billing or as soon thereafter as actual transport information
is available. Buyer will pay Seller by wire transfer in immediately available
funds to a depository designated by Seller on the later
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of the twenty-fourth (24th) day of the month, or fourteen (14) days after
receipt of such invoice. When the due date falls on a day that the designated
depository is not open in the normal course of business to receive Buyer's
payment, Buyer shall cause such payment to be actually received by Seller on or
before the last business day on which the designated depository is open prior to
such due date. If any overcharge or undercharge in any form whatsoever shall at
any time be found and the bill therefore has been paid, Seller shall refund the
amount of the overcharge received by Seller and Buyer shall pay the amount of
the undercharge within ten (10) days after final determination thereof; however,
no retroactive adjustment will be made for any overcharge or undercharge
identified later than a period of twenty-four (24) months from the date a
discrepancy occurred. In the event a dispute arises as to the amount payable in
any statement rendered, Buyer shall nevertheless pay the amount not in dispute
to Seller pending resolution of the dispute. If it is determined that Buyer
owes Seller the disputed amount, Buyer will pay Seller that amount. If Buyer
fails to pay the entire undisputed amount of any statement hereunder when it
becomes due, the unpaid amount shall bear interest from the due date until paid,
which interest shall be for Seller's sole account, and, in addition to any other
remedies, Seller may, upon thirty (30) days written notice to Buyer, terminate
deliveries of gas hereunder. Said interest rate shall be the prime rate as
established from time to time by First Security Bank of Idaho plus two percent
(2%). The late charge provided for herein shall be compounded monthly. If
either principal or late charges are due, any payments thereafter received shall
first be applied to the late charges due, then to the previously outstanding
principal due and lastly, to the most current principal due.
If any error is discovered in any statement rendered hereunder, such
error will be adjusted within thirty (30) days from the date of
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discovery, but no adjustment will be made for any error discovered more than two
(2) years after receipt of any such original statements.
11.02 The parties will keep and maintain true and accurate books,
records and accounts in respect of all statements, charges and computations made
under this Contract and will preserve these books, records and accounts for a
period of at least six (6) years after such statements, charges or computations
are made. Such shall be kept and maintained in accordance with generally
accepted accounting principles applied consistently from year to year and good
industry practices and distinguishable from all other books, records and
accounts.
Each party has the right, at its sole cost and upon providing
reasonable notice, to have a third-party auditor, who is a member of a
nationally recognized certified public accounting firm, audit on such party's
behalf during normal business hours the relevant accounts, books, records and
charts of the other party to the extent necessary to verify the accuracy of any
statement, charge, computation or demand made under or pursuant to any of the
provisions of this Contract. This right expires two (2) years after the
expiration of this Contract.
ARTICLE XII
TERM:
12.01 Subject to other terms and provisions hereof, this Contract shall
be effective November 1, 1993 and continue through and including September 30,
2008.
Notwithstanding the foregoing, it is the intent of the parties to
commence good faith negotiations for a new gas purchase contract no later than
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six (6) months prior to the expiration of this Contract. In the event of
termination for any reason, this Contract shall remain in full force and effect
to the extent necessary and for such additional term as may be required to
accommodate any imbalances between purchased and delivered volumes incurred
during the term hereof.
Notwithstanding the expiration of this Contract, the provisions
respecting liability and indemnification to the extent of any liabilities which
may have accrued prior to the date of termination of this Contract, and the
provisions respecting confidentiality, maintenance of records, payment and audit
rights shall remain in full force and effect in accordance with their terms.
ARTICLE XIII
FORCE MAJEURE:
13.01 Immediately upon becoming aware of the occurrence of an event of
force majeure, the party affected shall give notice thereof to the other party
describing such event or condition, stating the specific obligations hereunder,
the performance of which are, or are expected to be, delayed, reduced or
prevented, and (either in the original or in supplemental notices) stating the
estimated period during which performance may be suspended or reduced,
including, to the extent known or ascertainable, the estimated extent of such
effects on performance. Such notice of an event of force majeure is to be first
given by telephone or telecopy communication within twenty-four (24) hours of
the beginning of the event of force majeure, and then confirmed in writing
within five (5) days, giving particulars available to the reporting party, and
being supplemented if necessary within twenty (20) days to give full
particulars.
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If initial notice of an event of force majeure is given within twenty-
four (24) hours to the other party after the occurrence of the cause relied on,
then the obligations of the party giving notice, so far as they are affected by
such force majeure event, from its inception, shall be suspended during the
continuance of any inability so caused, but for no longer period. If initial
notice of an event of force majeure is not given within twenty-four (24) hours,
to the other party, after the occurrence of the cause relied on, then the
obligation of the party giving notice, so far as they are affected by such force
majeure event, from time of the notice given, shall be suspended during the
continuance of any inability so caused, but for no longer period.
The party claiming suspension will give notice as soon as possible
after the force majeure event is remedied, to the effect that the same has been
remedied and that such party has resumed, or is then in a position to resume,
the performance of such covenants or obligations. Notice shall also be given
when the remedy or resumption is only partial.
13.02 The obligations of a party hereunder shall be suspended, during
the time and to the extent, that it is prevented from complying with its
obligations in whole or in part by an event of force majeure which shall mean:
(a) an Act of God, including flood, fire, storms, explosion,
lightning, landslides or earthquakes;
(b) an act of the Queen's or public enemies, including war,
revolution, insurrection, riot, blockade, civil disturbance or
any other unlawful act against public order and authority;
(c) a strike, lockout or other industrial disturbance;
(d) breakdown of, or injury to, or the necessity of making repairs or
alterations to, any facilities used in or for the production,
transportation, processing, handling or delivery of
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the gas;
(e) the inability to acquire or delays in acquiring, at reasonable
cost and after the exercise of reasonable diligence, any
servitudes, right-of-way grants, permits or licenses required to
be obtained to enable a party hereto to fulfill its obligations
hereunder;
(f) substantial loss of Buyer's system supply markets due to factors
other than price;
(g) laws, orders, rules or regulations of any governmental authority
claiming jurisdiction, or any other governmental restraint, or
injunctions or other legal proceedings;
(h) any other event, whether or not the kind enumerated above, which
is not reasonably within the control the party claiming to be
excused.
It is understood and agreed that the settlement of strikes or lockouts
shall be entirely within the discretion of the party having the difficulty, and
that the above requirement of the use of diligence in restoring normal operating
conditions shall not require the settlement of strikes or lockouts by acceding
to the terms of the opposing party when such course is inadvisable in the
discretion of the party having the difficulty.
13.03 The parties hereto recognize that all or part of the gas
purchased by Buyer from Seller shall be received and transported by a Pipeline
owned by a third party transporter pursuant to a separate written agreement
between transporter and either one of the parties hereto. Following
commencement of deliveries of gas hereunder, should any third party transporter
for any cause beyond their control and beyond the control of either party
hereto, be unable
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or unwilling to transport any volume of subject gas, Seller's obligation to
deliver and Buyer's obligation to receive gas shall be suspended as though such
lack of transportation constitutes an event of force majeure.
13.04 Neither party shall be entitled to benefit from the provisions of
this Article XIII - FORCE MAJEURE to the extent that failure of performance is
caused by the party claiming suspension having failed with reasonable dispatch
to remedy the condition by taking reasonable acts within its control or to
resume performance of suspended obligations.
13.05 Lack of finances shall not be considered an event of force
majeure. Nor shall an event of force majeure suspend any obligation for the
payment of money due hereunder whether or not such money becomes due before or
after the declaration of an event of force majeure, except as provided for in
Section 13.06.
13.06 The declaration of an event of force majeure by Buyer hereunder
shall not relieve Buyer of its obligation to pay the Reservation Fee, NOVA
Demand Charge and ANG Demand Charge as defined in Sections 10.01(a), (b) and
(c), respectively.
If the declaration of an event of force majeure by Seller hereunder
results in relief from all or a portion of the NOVA Demand Charge, such relief
shall be passed on to the Buyer. Declaration of an event of force majeure by
the Seller shall relieve the Buyer of its obligation to pay the Reservation Fee
as defined in Section 10.01(a) throughout the course of the event of force
majeure.
13.07 If an event of force majeure affecting Buyer's ability to take
gas occurs, Buyer shall first curtail purchases of all interruptible gas
supplies which could be physically replaced by gas purchased pursuant to this
Contract prior to reducing the purchases of gas hereunder. Buyer's ability to
reduce purchases shall be limited to this Contract's pro rata share of the total
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quantity of firm gas purchased by Buyer for delivery at the Delivery Point via
the PGT Expansion Facilities to serve Buyer's core market customers.
If an event of force majeure affecting Seller's ability to deliver gas
occurs, Seller shall first curtail all deliveries of interruptible gas prior to
reducing the deliveries of gas hereunder. Seller shall only reduce deliveries
hereunder on a pro rata basis with other firm sales of gas.
13.08 During periods when Buyer is unable to take delivery of the gas
hereunder by reason of an event of force majeure, Seller shall have the right to
sell such gas to other third parties provided that such sales will not interfere
with nor preclude Seller from subsequently performing its obligations hereunder
after the event of force majeure has ceased to operate.
13.09 During periods when Seller is unable to deliver gas hereunder by
reason of an event of force majeure, Buyer shall have the right to purchase
natural gas or other fuels from other third parties provided that such purchases
will not interfere with nor preclude Buyer from subsequently performing its
obligations hereunder after the event of force majeure has ceased to operate.
13.10 If either party claims an event of force majeure which results in
the total suspension of gas deliveries for either a period of forty five (45)
consecutive days or a cumulative sixty (60) days in any Contract Year, then the
party not invoking force majeure may, within thirty (30) days following
occurrence of either such event give notice to the other party of its election
to terminate this Contract upon thirty (30) days prior written notice and this
Contract shall terminate at the expiration of such notice period.
13.11 Failure to deliver or accept delivery of gas which is excused by
or results from the operation of any provision of this Contract shall not extend
the term.
13.12 If Seller can reasonably demonstrate that the continued sale of
gas
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hereunder would be uneconomic as a result of:
(a) a new or increased tax (other than income tax), governmental fee,
duty or royalty imposed subsequent to the date of this Contract;
or
(b) an increase in NOVA, ANG or PGT tolls and tariffs or a
significant change in toll design imposed subsequent to the date
of this Contract,
which would be payable by Seller, then Seller and Buyer shall commence
renegotiation of the Delivery Point Selling Price or responsibility for NOVA,
ANG and PGT tolls and tariffs, as the case may be, within seven (7) days after
Seller's notice to Buyer of such uneconomic circumstances. If Buyer and Seller
are unable to reach agreement within fifteen (15) days of the commencement of
such renegotiation, Seller may terminate this Contract at any time upon at least
forty five (45) days prior written notice to this effect being given to Buyer
within sixty (60) days of such renegotiations ceasing. Any revised Delivery
Point Selling Price or change in responsibility for NOVA, ANG and PGT tolls and
tariffs, resulting from this renegotiation shall become effective upon the date
of agreement between the parties and Article X - PRICE shall be amended
accordingly.
13.13 If Buyer can reasonably demonstrate that the continued purchase
of gas by Buyer hereunder would be uneconomic as a result of:
(a) a new or increased tax (other than income tax), governmental fee,
duty or royalty imposed subsequent to the date of this Contract;
or
(b) an increase in NOVA, ANG or PGT tolls and tariffs or a
significant change in toll design imposed subsequent to the date
of this Contract,
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which would be payable by Buyer, then Seller and Buyer shall commence
renegotiation of the Delivery Point Selling Price within seven (7) days after
Buyer's notice to Seller of such uneconomic circumstances. If Buyer and Seller
are unable to reach agreement within fifteen (15) days of the commencement of
such renegotiation, Buyer may terminate this Contract upon at least forty five
(45) days prior written notice to this effect being given to Seller within sixty
(60) days of such renegotiations ceasing. Any revised Delivery Point Selling
Price or change in responsibility for NOVA, ANG and PGT tolls and tariffs,
resulting from this renegotiation shall become effective upon the date of
agreement between the parties and Article X - PRICE shall be amended
accordingly.
ARTICLE XIV
ARBITRATION:
14.01 Any Dispute between the Buyer and Seller in respect of the annual
renegotiation of the Delivery Point Selling Price hereunder, as contemplated
pursuant to Section 10.01 herein, and any other controversy or claim, except as
expressly provided for herein, arising out of or relating to this Contract, or
the scope thereof, which the parties agree to submit to arbitration (hereinafter
referred to as a "Dispute"), shall be submitted to and finally settled by
arbitration pursuant to the provisions of this Article XIV. There are two
circumstances where arbitration may be conducted under this Article XIV. First,
a Dispute regarding the Delivery Point Selling Price pursuant to Article X -
PRICE herein is subject to "price arbitration". Second, any other Dispute shall
be subject to nonprice arbitration. The provisions of this Article XIV apply to
both kinds of arbitration unless expressly applicable to only one kind.
14.02 Where a Dispute is to be arbitrated pursuant to this Contract,
the
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parties shall attempt to mutually appoint a single arbitrator. If the parties
are unable to do so within fifteen (15) days after the end of the price
negotiation period described in Section 10.03 herein, then upon written request
of either party and within ten (10) days of receipt of such request, each party
shall appoint an arbitrator and notify the other party of such appointment.
Should a party not appoint an arbitrator within such time, the other party shall
select the second arbitrator within ten (10) days. The two arbitrators so
appointed shall promptly appoint a third arbitrator within ten (10) days after
appointment of the second arbitrator. If they fail to do so within such time,
the third arbitrator shall be appointed within the next ten (10) days by the AAA
in accordance with its rules as described in this Contract. For purposes of
such selection, the AAA shall provide a list of at least ten (10) qualified
persons in accordance with the requirements of its rules as modified herein.
The persons so proposed and the arbitrator so selected can be of any
nationality.
The arbitrators shall generally be qualified by education and
experience to pass upon the matters involved in the Dispute. A third arbitrator
selected by the AAA for a price arbitration must be qualified to determine
natural gas marketing issues.
If any arbitrator dies, becomes disqualified or incapacitated, or
fails or refuses to act before the matter or matters subjected to the
arbitration has been decided, then in place of such arbitrator, a replacement
arbitrator shall promptly be appointed in the same manner and by the same party
as the arbitrator to be replaced.
14.03 If the annual renegotiation of the Delivery Point Selling Price
is submitted and settled by arbitration three times during the term of this
Contract, either party may, by written notice, terminate this Contract. Such
termination notice shall be given within fifteen (15) days of the written
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decision of the third arbitrated pricing determination and shall be effective on
the next following Contract year anniversary date.
14.04 In a Dispute under Article X - PRICE, each party shall within
fifteen (15) days after appointment of the last arbitrator submit to the
arbitrator(s) and the other party its written final offer of the Delivery Point
Selling Price (the "Final Offer"). Each Final Offer will then be opened and
reviewed by the parties hereto in the presence of the arbitrator(s). The
parties will then determine if the differences in the Final Offers can be
bridged by negotiation. If not, then the arbitrator(s) must choose one of the
Final Offers and cannot decide any other Delivery Point Selling Price. If a
party fails to make a timely Final Offer, the timely submitted Final Offer from
the other party shall be adopted by the arbitrator(s) as the arbitration
decision. Except as in the preceding sentence, the arbitrator(s) shall choose
the Final Offer which better represents the market price for gas to be sold
under this Contract during the Contract year at issue, giving due consideration
to the then current Delivery Point Selling Price, the Delivery Point Selling
Price resulting from each Final Offer, the prices of substitutable energy
sources, the price of other gas sold under similar type terms and conditions
that competes in the same or similar markets as those being served by the Buyer
or the Seller, the general intent and objectives of this Contract and the
parties' desire to maintain a long-term, mutually beneficial relationship. If
other gas supply contracts are used for comparative purposes in such
arbitration, all of the terms and conditions of such contracts relative to the
provisions of this Contract are to be considered. Any confidential information,
including without limitation other gas supply contracts, which are used in the
arbitration, shall be kept confidential by the parties and the arbitrators and
shall not be disclosed to any other person.
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14.05 Unless otherwise agreed to by the parties, the arbitration shall
be held in Seattle, Washington. The arbitrator(s) shall proceed promptly and
diligently and render a decision as soon as practicable. In a Dispute under
Article X - PRICE, the arbitrator(s) shall decide within forty-five (45) days
after receipt of Final Offers from both parties.
14.06 The decision of the arbitrator(s) shall be final and binding on
the parties from which no appeal may be taken, and an order confirming the
decision or judgement upon the decision may be entered in any court having
jurisdiction. The parties agree that the decision of the arbitrator(s) shall be
the sole and exclusive remedy between them regarding the Dispute submitted to
arbitration.
14.07 Each party shall bear its own witness and attorney's fees in the
arbitration, however, it shall be within the arbitrator(s) sole discretion and
authority to award all costs and fees to the prevailing party. The fees and
expenses of the single arbitrator or the arbitrators and the fees charged by the
arbitral institution and its costs in providing arbitration services under this
Article XIV - ARBITRATION, shall be paid in full by the party whose Final Offer
was not accepted under a "price arbitration" pursuant to Section 14.05.
14.08 The arbitrator(s) may grant such provisional remedies as it or
they deem necessary and appropriate related to the Dispute in its or their sole
discretion. Notwithstanding the initiation of an arbitration, each party shall
continue to perform all duties and obligations under this Contract.
14.09 Buyer and Seller agree that the Delivery Point Selling Price
determined pursuant to a "price arbitration" under this Article XIV -
ARBITRATION must take into consideration a component that compensates Seller for
its gas aggregation and administrative service efforts required for Seller's
performance under this Contract at the rate of [CONFIDENTIAL INFORMATION OMITTED
AND FILED SEPARATELY WITH THE COMMISSION] per MMBTU and
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<PAGE>
the arbitrator(s) should be so instructed prior to arbitration.
14.10 If the decision of the arbitrator(s) is not final by the
commencement of the relevant Contract year, the parties shall use, on an interim
basis for the new Contract year, as a Delivery Point Selling Price, the higher
of the Delivery Point Selling Price for the immediately preceding Contract year
and the last offer in respect of the Delivery Point Selling Price for the new
Contract year made by the Buyer prior to the commencement of the new Contract
year. The decision of the arbitrator shall be retroactive to the beginning of
the Contract year, if necessary. Upon determination of the Delivery Point
Selling Price, interest at the rate specified in Section 11.01 herein, shall be
applied for any period of retroactivity to any overpayment or underpayment, as
the case may be.
ARTICLE XV
CONFIDENTIALITY:
15.01 Buyer and Seller agree that the terms of this Contract and any
resulting transaction shall be kept strictly confidential, except to the extent
required by applicable law, and except to the extent either party is required to
disclose pertinent information concerning this Contract to lenders, underwriters
or regulators within the normal course of business and except for the release of
a mutually agreeable summary of contract terms. If either party makes such
disclosure, it shall advise the lenders, underwriters or regulators that the
information disclosed is strictly confidential.
ARTICLE XVI
TAXES:
16.01 Seller agrees to pay or cause to be paid, all taxes and assess-
ments lawfully levied and imposed upon Seller with respect to the gas delivered
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hereunder prior to its delivery to Buyer at the Delivery Point, including but
not limited to all taxes imposed by provincial, state or federal authority on
the production, severance, gathering and delivery with respect to the gas
delivered hereunder. Buyer agrees to pay, or cause to be paid, all taxes and
assessments lawfully levied and imposed upon Buyer including, but not limited
to, any applicable franchise fees and the applicable U.S. Customs fees with
respect to the gas delivered hereunder after its receipt by Buyer at the
Delivery Point. Neither party shall be responsible or liable for any taxes or
other statutory charges levied or assessed against any of the facilities of
the other party used for the purpose of carrying out the provisions of this
Contract.
ARTICLE XVII
OFF-PEAK SALES:
17.01 As reimbursement to Seller for its commitment for firm service
on the NOVA pipeline facilities and firm gas supplies hereunder, Buyer
understands and agrees that while Buyer's commitment to firm service on PGT and
ANG as to firm delivery and payment of related demand charges is for the above
defined Winter Period only each Contract year, Buyer shall be obligated to pay
Seller for the Reservation Fee and NOVA Demand Charge component of the Delivery
Point Selling Price as defined in Section 10.01(a) and (b), respectively,
throughout each Contract year.
17.02 Seller currently has access to firm and interruptible
transportation service on the PGT system for delivery to Stanfield, Oregon, the
interconnect with Northwest's facilities. Accordingly, Seller shall act as
Buyer's administrative service agent on a daily basis for any amount of the MDQ
not being utilized by Buyer for any reason, including but not limited to the
declaration by Buyer of an event of force majeure, whereby Seller will use all
reasonable efforts to market the gas supply subject to this Contract, and
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<PAGE>
not utilized by Buyer, to other markets served by Seller. This gas will be so
marketed together with the related NOVA and, during the Winter Period, ANG firm
transportation capacity on an interruptible basis, subject to immediate Winter
Period recall by Buyer, as required by Buyer's firm customers, for the next
succeeding gas day. For this off-peak sales service Buyer agrees to pay Seller
three cents ($0.03) per MMBTU, as provided for by Section 17.03 below, for each
MMBTU so marketed by Seller during the Winter Period. All volumes so marketed
will be credited toward Buyer's take commitment pursuant to Section 8.02 herein.
17.03 For each MMBTU of the MDQ not requested by Buyer on a daily basis
throughout the Winter Period of each Contract year and ultimately sold to other
of Seller's markets, Seller shall reimburse Buyer certain amounts, not to exceed
the total cost to Buyer of all applicable NOVA and ANG Demand Charges and the
Reservation Fee associated with the purchase and transportation of the marketed
volumes. Seller will pay, from the proceeds of the sale, all gas purchase costs
and transportation commodity charges and deduct Seller's administrative service
fee pursuant to Section 17.02 herein prior to calculating the reimbursement due
Buyer, as follows:
Seller's Market Selling Price
including transportation charges
(as delivered at Stanfield) $ X.XX
Less:
Seller's Administrative
Service Fee [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]
Gas Commodity Charge Component
of Delivery Point Selling Price (X.XX)
Transportation commodity
charges (NOVA, ANG and PGT) (.XX)
-------
Amount available for Demand Charge and
Reservation Fee reimbursement to Buyer $ .XX
------
------
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<PAGE>
17.04 During periods of each Contract year other than the Winter Period
as defined hereunder, Seller will use all reasonable efforts to market use of
the NOVA firm delivery and receipt capacity subject to this Contract. For all
capacity so marketed, Seller will reimburse to Buyer any amounts charged for
NOVA transportation in excess of the NOVA tariffed firm transportation commodity
rate levels with such reimbursement not to exceed the actual NOVA Demand Charge
defined herein.
17.05 On any day during each Contract year Seller is obligated to use
all reasonable efforts to so market use of the gas supply and related NOVA firm
delivery and receipt capacity and ANG firm transportation capacity hereunder
pursuant to Sections 17.02, 17.03 and 17.04 herein. Seller and Buyer understand
and agree that to the extent Seller cannot so market such supply and related
capacity as described above or to the extent Buyer is able to secure a market
which results in a greater cost mitigation to Buyer than Seller's market, then
Buyer shall be entitled to so market such gas supply and related capacity on
such day.
ARTICLE XVIII
SUPPLY ASSURANCE:
18.01 In the event Seller fails to deliver the daily volume of gas
nominated by Buyer, up to the MDQ, for reasons other than an event of force
majeure, Seller shall indemnify Buyer for those incremental gas costs
attributable to such failure giving due regard to the lowest reasonably
available price for such incremental gas supplies.
18.02 If, under any circumstances other than an event of force majeure,
Seller fails to deliver the volumes of gas nominated by Buyer, up to the MDQ,
for a total of ten (10) cumulative days during any Winter Period, then with
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fifteen (15) days prior written notice, Buyer may reduce the MDQ to the average
level actually delivered by Seller.
18.03 If, under any circumstances other than an event of force majeure,
Seller fails to deliver the volume of gas nominated by Buyer, up to the MDQ, for
a total of fifteen (15) cumulative days during any Winter Period, then with
thirty (30) days prior written notice, Buyer may terminate this Contract.
18.04 In no event shall Seller's liability under Section 18.01 herein
include any indirect, consequential or business losses, loss of profits, or
other costs or expenses that may be suffered by Buyer. In addition, Seller's
liability for failure to deliver gas shall not exceed $500,000 in any one
Contract year.
ARTICLE XIX
REGULATORY AND TRANSPORTATION AGREEMENT COMPLIANCE:
19.01 The party who is responsible under Article II - CONDITIONS
PRECEDENT and Article VII - PIPELINE TRANSPORTATION for obtaining regulatory
approvals and gas transportation agreements is also responsible for complying
with and maintaining such approvals and agreements over the term of this
Contract. In addition, the parties shall comply with all laws and regulations
applicable to the delivery of gas from Canada into the United States, regardless
of whether the Delivery Point is within or outside the United States. This
obligation shall include, but shall not be limited to, obtaining all necessary
permits, approvals, and orders, such as removal permits, export orders, and
import authorizations, and payment of all fees, charges or assessments required
as a result of the gas delivered hereunder being produced in or transported
through Canada, and into the United States. If one party is required to make
any payments or to incur any expenses to perform obligations attributable to the
other party, the other party shall be obligated to
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<PAGE>
reimburse such payments or expenses, the amount of which shall be determined by
mutual agreement of the parties or, absent such agreement, by arbitration
pursuant to Article XIV - ARBITRATION.
ARTICLE XX
EQUAL OPPORTUNITY CLAUSE
20.01 During the performance of this Contract, the Seller agrees as
follows:
a) The Seller will not discriminate against any employee or
applicant for employment because of race, color, religion, sex or national
origin. The Seller will take affirmative action to ensure that applicants are
employed, and that employees are treated during employment, without regard to
their race, color, religion, sex or national origin. Such action shall include,
but not be limited to the following: Employment, upgrading, demotion, or
transfer, recruitment or recruitment advertising; layoff or termination; rates
of pay or other forms of compensation; and selection for training, including
apprenticeship. The Seller agrees to post in conspicuous places, available to
employees and applicants for employment, notices to be provided by the
contracting officer setting forth the provisions of this nondiscrimination
clause.
b. The Seller will, in all solicitations or advertisements for
employees placed by or on behalf of the Seller, state that all qualified
applicants will receive consideration for employment without regard to race,
color, religion, sex or national origin.
c. The Seller will send to each labor union or representative or
workers with which he has a collective bargaining agreement or other contract or
understanding, a notice to be provided by the agency contracting officer,
advising the labor union or workers' representative of the Seller's
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<PAGE>
commitments under section 202 of the Executive Order 11246 of September 24,
1965, and shall post copies of the notice in conspicuous places available to
employees and applicants for employment.
d. The Seller will comply with all provisions of Executive Order
11246 of September 24, 1965, and of the rules, regulations, and relevant orders
of the Secretary of Labor.
e. The Seller will furnish all information and reports required by
Executive Order 11246 of September 24, 1965, and by the rules, regulations, and
orders of the Secretary of Labor, or pursuant thereto, and will permit access to
its books, records and accounts by the contracting agency and the Secretary of
Labor for purposes of investigation to ascertain compliance with such rules,
regulations, and orders.
f. In the event of the Seller's noncompliance with the
nondiscrimination clauses of this Contract or with any of such rules,
regulations, or orders, this Contract may be cancelled, terminated or suspended
in whole or in part and the Seller may be declared ineligible for further
Government contracts in accordance with procedures authorized in Executive Order
11246 of September 24, 1965, and such other sanctions may be imposed and
remedies invoked as provided in Executive Order 11246 of September 24, 1965, or
by rule, regulation, or order of the Secretary of Labor, or as otherwise
provided by law.
g. The Seller will include the provisions of paragraphs (a) through
(g) in every subcontract or purchase order unless exempted by rules, regulations
or orders of the Secretary of Labor issued pursuant to Section 204 of Executive
Order 11246 of September 24, 1965, so that such provisions will be binding upon
each subcontractor or vendor. The Seller will take such action with respect to
any subcontract or purchase order as may be directed by the Secretary of Labor
as a means of enforcing such provisions including
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<PAGE>
sanctions for noncompliance: PROVIDED, HOWEVER, that in the event the Seller
becomes involved in, or is threatened with, litigation with a subcontractor or
vendor as a result of such direction, the Seller may request the United States
to enter into such litigation to protect the interests of the United States.
ARTICLE XXI
GENERAL TERMS:
21.01 The parties specifically recognize that the performance under this
Contract is subject to all valid laws, orders, judgements, regulations, or
otherwise, of courts or regulatory bodies having proper jurisdiction.
21.02 Neither party may assign this Contract or any of its rights
hereunder without the prior written consent of the other party, which consent
may not be unreasonably withheld, provided, however, that consent is hereby
given to either party for assignment of this Contract to the extent required to
secure bona fide indebtedness of either party.
21.03 Seller warrants title to all gas delivered to Buyer hereunder and
warrants that Seller has authority to sell same under the terms of this
Contract. Seller hereby agrees to indemnify and save Buyer harmless from any
and all suits, claims and liens of whatsoever nature relating to the title
thereto. Seller agrees to indemnify, defend and save Buyer harmless from any
and all liability or loss of any kind or character incident to the payment of
all royalties and other payments for interest in production due the owners
thereof in accordance with the terms of the oil and gas leases and other
instruments affecting production from the wells delivering gas hereunder.
21.04 As between the parties hereto, Seller shall be in control and in
possession of the gas deliverable hereunder and responsible for any damages or
injuries caused thereby until the same shall have been delivered to Buyer at
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<PAGE>
the Delivery Point(s), except injuries and damages which shall be occasioned
solely and proximately by the negligence of Buyer. As between the parties
hereto, after receipt of the gas, Buyer shall be deemed to be in exclusive
control of and responsible for any injuries or damages caused thereby, except
injuries and damages which shall be occasioned solely and proximately by the
negligence of Seller.
21.05 Each party will indemnify, defend and hold harmless the other
party and its partners, officers, employees and agents from any and all claims,
suits, actions, damages, costs (including, without limitation, reasonable
attorney fees at trial and on appeal) or liabilities to the extent arising from
the indemnifying party's failure to perform its obligation hereunder or breach
of its representations of covenants hereunder.
21.06 In no event shall Buyer or Seller be liable to the other party
for any indirect, consequential, punitive or special damages incurred,
including, without limitation, loss of profits or income, loss of business
expectations, business interruptions, loss of contract or any damage to third
parties arising in any way out of this Contract or any breach thereof, except
for obligations to NOVA or ANG provided hereunder and except for Buyer's rights
as specified under Article XVIII - SUPPLY ASSURANCE, Section 18.01.
21.07 In addition to other remedies that may be available, in the event
either party shall be in substantial breach of the terms of this Contract, and
shall not have cured such breach within thirty (30) days after such notice of
substantial breach by the other party, the party not in breach shall have the
right to terminate this Contract upon thirty (30) days written notice to the
party in breach. For purposes of this provision, supply failure shall not be
considered a breach until the duration of the failure exceeds the limits of
Article XVIII - SUPPLY ASSURANCE. However, the provisions of this Section 21.07
shall not govern Buyer's termination rights under Article XVIII - SUPPLY
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<PAGE>
ASSURANCE, or either party's terminations rights under Article XIII - FORCE
MAJEURE, Section 13.10.
21.08 The waiver by either party of any breach of any of the provisions of
this Contract shall not constitute a continuing waiver of other breaches of the
same or other provisions of this Contract.
21.09 This Contract constitutes the entire agreement among the parties
pertaining to the subject matter hereof, and supersedes all prior agreements
and understandings pertaining thereto. The terms of this Contract may not be
changed unless the parties agree to such changes in writing.
21.10 This Contract may be executed in counterparts, all of which together
shall constitute one agreement binding on all the parties.
21.11 Each provision of this Contract shall be considered separable and if
for any reason any provision or provisions herein are determined to be invalid
and contrary to any existing or future law, such invalidity shall not impair the
operation of or affect those portions of this Contract which are valid.
21.12 Except for the initial notice requirements pursuant to Section 13.01
herein, any notice, statement, demand, or other communication (in this Section
referred to as a "Communication") required or permitted to be given or made in
connection with this Contract shall be in writing and shall be well and
sufficiently given or made:
if sent to Buyer, addressed to:
BUYER
Cascade Natural Gas Corporation
222 Fairview Avenue North
P.O. Box 24464
Seattle, Washington 98124
Attn: Vice President, Gas Supply
Telephone No.: (206) 624-3900
Telecopy No. : (206) 624-7215
and if sent to Seller, addressed to:
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<PAGE>
IGI Resources, Inc.
Lakepointe Centre I
300 Mallard Drive, Suite 350
Boise, Idaho 83706
Attn: Executive Vice President, Chief Operating Officer
Telephone No.: (208) 387-0500
Telecopy No.: (208) 387-0530
Each Communication sent in accordance with this Section 21.12 shall be
deemed to have been received:
a) on the day it was delivered, if delivered;
b) on the third Business Day after it was mailed, if mailed by
registered mail as aforesaid or on the fifth Business Day after it was mailed,
if mailed by ordinary mail as aforesaid (excluding in each case each day on
which there is any interruption of postal services due to strike, lockout or
other cause); and
c) on the same day that it was sent by telecopy or other electronic
communication as aforesaid, or on the first Business Day thereafter if the day
on which it was sent by telecopy or other electronic communication was not a
Business Day.
Either party may from time to time change its address for notice by
giving notice to the other party hereto in the aforesaid manner.
21.13 Each of the parties shall from time to time and at all times do
such further acts as shall be reasonably required in order to fully perform and
carry out the terms of this Contract.
21.14 All references in this Contract to prices, costs, money or
amounts shall be in United States currency.
21.15 The validity, construction, interpretation and effect of this
Contract shall be governed by the laws of the State of Washington.
21.16 Time is of the essence of this Contract.
<PAGE>
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<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Contract to be
effective as of the day and year written above.
"BUYER"
CASCADE NATURAL GAS CORPORATION
By: ________________________________
Name: ______________________________
Title: _____________________________
"SELLER"
IGI RESOURCES, INC.
By: ________________________________
Randy Schultz
Executive Vice President
Chief Operating Officer
"THIS IS THE SIGNATURE PAGE ATTACHED TO AND MADE A PART OF THE GAS PURCHASE
CONTRACT AS OF OCTOBER 1, 1994 BETWEEN IGI RESOURCES, INC. AND CASCADE NATURAL
GAS CORPORATION."
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<PAGE>
EXHIBIT "A"
To The
GAS PURCHASE CONTRACT
As of: October 1, 1994
Between
CASCADE NATURAL GAS CORPORATION ("BUYER")
and
IGI RESOURCES, INC. ("SELLER")
Effective Date of this Exhibit "A": October 1, 1994
-------------------
Ending Date of this Exhibit "A": September 30, 1995
----------------------
DELIVERY POINT As defined in Section 1.01(g)
of the Contract noted above
MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446
DELIVERY POINT SELLING PRICE 1/
-
____________
1. The Delivery Point Selling Price shall be equal to [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]per MMBTU
at AECO-C Hub plus the actual cost of firm NOVA re-delivery service
and firm ANG receipt and re-delivery service plus any applicable
allowance for fuel-in-kind associated with such services.
"BUYER"
CASCADE NATURAL GAS CORPORATION
By: ________________________________
Name: ______________________________
Title: _____________________________
"SELLER"
IGI RESOURCES, INC.
By: ________________________________
Randy Schultz
Executive Vice President
Chief Operating Officer
<PAGE>
EXHIBIT "A"
To The
GAS PURCHASE CONTRACT
As of: October 1, 1994
Between
CASCADE NATURAL GAS CORPORATION ("BUYER")
and
IGI RESOURCES, INC. ("SELLER")
Effective Date of this Exhibit "A": November 1, 1993
--------------------
Ending Date of this Exhibit "A": September 30, 1994
----------------------
DELIVERY POINT As defined in Section 1.01(g)
of the Contract noted above
MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446
DELIVERY POINT SELLING PRICE [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]
"BUYER"
CASCADE NATURAL GAS CORPORATION
By: _____________________________
Name: ___________________________
Title: __________________________
"SELLER"
IGI RESOURCES, INC.
By: _____________________________
Randy Schultz
Executive Vice President
<PAGE>
Chief Operating Officer
<PAGE>
INDEX
Page
----
ARTICLE 1
DEFINITIONS AND INTERPRETATION
1.1 Definition. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
1.2 Headings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.3 Interpretation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.4 Hereof, etc.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.5 Industry Usage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
1.6 Currency. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
ARTICLE 2
LONG TERM AUTHORIZATIONS
2.1 ERCB Long Term Removal Permit . . . . . . . . . . . . . . . . . . . . . . 7
2.2 NEB Long Term Export Licence. . . . . . . . . . . . . . . . . . . . . . . 8
2.3 Long Term Import Authorization. . . . . . . . . . . . . . . . . . . . . . 8
2.4 Further Applications. . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.5 Producer Support. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
2.6 Diligent Efforts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.7 Prior Review. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.8 Approval of Authorization . . . . . . . . . . . . . . . . . . . . . . . . 9
2.9 Denial of Authorization . . . . . . . . . . . . . . . . . . . . . . . . . 9
2.10 Termination of Agreement. . . . . . . . . . . . . . . . . . . . . . . . .10
2.11 Maintenance of Authorizations . . . . . . . . . . . . . . . . . . . . . .10
ARTICLE 3
TRANSPORTATION MATTERS
3.1 Seller's Arrangements . . . . . . . . . . . . . . . . . . . . . . . . . .10
3.2 Buyer's Arrangements. . . . . . . . . . . . . . . . . . . . . . . . . . .11
3.3 Use of Seller's Transportation Arrangements . . . . . . . . . . . . . . .11
3.4 Change in Transportation Tolls and Tariffs. . . . . . . . . . . . . . . .11
3.5 Transportation Penalties. . . . . . . . . . . . . . . . . . . . . . . . .12
ARTICLE 4
QUANTITY OF GAS
4.1 Obligation to Sell and Deliver. . . . . . . . . . . . . . . . . . . . . .12
4.2 Nominations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
4.3 Minimum Purchase Quantity . . . . . . . . . . . . . . . . . . . . . . . .12
(i)
<PAGE>
ARTICLE 5
QUALITY AND MEASUREMENT
5.1 ANG Quality and Pressure Standard . . . . . . . . . . . . . . . . . . . .13
5.2 Delivery in a Common Stream . . . . . . . . . . . . . . . . . . . . . . .13
5.3 ANG Measurements. . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
5.4 Measurement Standards . . . . . . . . . . . . . . . . . . . . . . . . . .13
5.5 Unit Conversions. . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
ARTICLE 6
POSSESSION, TITLE AND WARRANTY
6.1 Transfer of Title . . . . . . . . . . . . . . . . . . . . . . . . . . . .14
6.2 Risk. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .14
6.3 Title and Indemnity . . . . . . . . . . . . . . . . . . . . . . . . . . .14
ARTICLE 7
GAS PRICING
7.1 Total Amounts to be Paid to Seller. . . . . . . . . . . . . . . . . . . .14
7.2 Nova Demand Charges . . . . . . . . . . . . . . . . . . . . . . . . . . .15
7.3 Nova Commodity Charges. . . . . . . . . . . . . . . . . . . . . . . . . .15
7.4 ANG Demand Charges. . . . . . . . . . . . . . . . . . . . . . . . . . . .15
7.5 ANG Commodity Charges . . . . . . . . . . . . . . . . . . . . . . . . . .15
7.6 Demand Charges Payment. . . . . . . . . . . . . . . . . . . . . . . . . .15
7.7 Gas Commodity Charges . . . . . . . . . . . . . . . . . . . . . . . . . .16
7.8 Gas Commodity Price . . . . . . . . . . . . . . . . . . . . . . . . . . .16
7.9 Supplier Demand Charges . . . . . . . . . . . . . . . . . . . . . . . . .16
7.10 Supplier Demand Fee . . . . . . . . . . . . . . . . . . . . . . . . . . .17
7.11 Kingsgate Administration Charges. . . . . . . . . . . . . . . . . . . . .17
7.12 Kingsgate Administration Fee. . . . . . . . . . . . . . . . . . . . . . .17
7.13 Redetermination of Kingsgate Administration Fee . . . . . . . . . . . . .17
7.14 Redetermination of Gas Commodity Price. . . . . . . . . . . . . . . . . .18
7.15 Requisite Producer Support. . . . . . . . . . . . . . . . . . . . . . . .19
ARTICLE 8
SECURITY OF SUPPLY
8.1 Source of Gas Supply. . . . . . . . . . . . . . . . . . . . . . . . . . .19
ARTICLE 9
SUPPLY FAILURE
INDEMNITY AND MITIGATION
9.1 Notice of Supply Failure and Seller Mitigation Effort . . . . . . . . . .19
9.2 Seller's Delivery Failure Indemnity . . . . . . . . . . . . . . . . . . .20
9.3 Buyer to Mitigate . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
9.4 Delivery Make Up Rights . . . . . . . . . . . . . . . . . . . . . . . . .20
9.5 Termination Rights for Extended Supply Failure. . . . . . . . . . . . . .20
9.6 Notice of Anticipated Supply Failure. . . . . . . . . . . . . . . . . . .21
9.7 DCQ Reduction Rights for Extended Supply Failure. . . . . . . . . . . . .21
9.8 Demand Charge Reduction Upon Supply Failure . . . . . . . . . . . . . . .21
9.9 Limitation on Seller's Liability. . . . . . . . . . . . . . . . . . . . .22
9.10 Limitation on Parties' Liabilities. . . . . . . . . . . . . . . . . . . .22
ARTICLE 10
TAXES
10.1 Payment of Taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
10.2 Prices Exclusive of Taxes . . . . . . . . . . . . . . . . . . . . . . . .23
10.3 Goods and Services Tax. . . . . . . . . . . . . . . . . . . . . . . . . .23
(ii)
<PAGE>
ARTICLE 11
TERM OF AGREEMENT
11.1 Term. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23
11.2 Effect of Termination . . . . . . . . . . . . . . . . . . . . . . . . . .24
ARTICLE 12
FORCE MAJEURE
12.1 Suspension. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24
12.2 Definition of Force Majeure . . . . . . . . . . . . . . . . . . . . . . .24
12.3 Exceptions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25
12.4 Resumption of Obligations . . . . . . . . . . . . . . . . . . . . . . . .25
12.5 Settlement of Industrial Disputes . . . . . . . . . . . . . . . . . . . .25
12.6 Effect on Demand Charge Payment Obligations . . . . . . . . . . . . . . .26
12.7 Termination for Extended Force Majeure Period . . . . . . . . . . . . . .27
12.8 Alternative Supplies During Force Majeure Period. . . . . . . . . . . . .27
12.9 Pro Rata Treatment. . . . . . . . . . . . . . . . . . . . . . . . . . . .27
12.10 No Extension to Term . . . . . . . . . . . . . . . . . . . . . . . .28
ARTICLE 13
BILLINGS AND PAYMENTS
13.1 Monthly Invoice . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28
13.2 Payment Due Date. . . . . . . . . . . . . . . . . . . . . . . . . . . . .29
13.3 Examination of Records. . . . . . . . . . . . . . . . . . . . . . . . . .29
13.4 Remedies for Non-Payment. . . . . . . . . . . . . . . . . . . . . . . . .29
13.5 Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
13.6 Limitation on Disputes. . . . . . . . . . . . . . . . . . . . . . . . . .30
(iii)
<PAGE>
ARTICLE 14
NOTICE
14.1 Service of Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . .31
14.2 Addresses and Numbers for Notices . . . . . . . . . . . . . . . . . . . .31
14.3 Right to Change Address and Numbers . . . . . . . . . . . . . . . . . . .32
ARTICLE 15
ASSIGNMENT
15.1 No Assignment of Agreement Without Consent. . . . . . . . . . . . . . . .32
15.2 Assignments By Way of Security. . . . . . . . . . . . . . . . . . . . . .33
15.3 EnurementEnurement. . . . . . . . . . . . . . . . . . . . . . . . . . . .33
ARTICLE 16
ARBITRATION
16.1 Submissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33
16.2 Selection of Arbitral Institution . . . . . . . . . . . . . . . . . . . .33
16.3 Commencement of Proceedings . . . . . . . . . . . . . . . . . . . . . . .33
16.4 Appointment of Arbitrators. . . . . . . . . . . . . . . . . . . . . . . .34
16.5 Experience. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34
16.6 Location of Arbitration Hearing . . . . . . . . . . . . . . . . . . . . .34
16.7 Hearing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34
16.8 Decision. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34
16.9 Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35
16.10 Failure to Participate . . . . . . . . . . . . . . . . . . . . . . .35
16.11 Provisional Remedies . . . . . . . . . . . . . . . . . . . . . . . .35
16.12 Arbitration Procedures . . . . . . . . . . . . . . . . . . . . . . .35
16.13 Continuation of Operations . . . . . . . . . . . . . . . . . . . . .35
16.14 Modification of Certain AAA Rules. . . . . . . . . . . . . . . . . .35
ARTICLE 17
FINAL OFFER ARBITRATION
17.1 Submissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36
17.2 Selection of Arbitral Institution . . . . . . . . . . . . . . . . . . . .36
17.3 Commencement of Proceeding. . . . . . . . . . . . . . . . . . . . . . . .36
17.4 Appointment of Arbitrators. . . . . . . . . . . . . . . . . . . . . . . .36
17.5 Experience. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37
17.6 Location of Final offer Arbitration . . . . . . . . . . . . . . . . . . .37
17.7 Final Offers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37
17.8 No Hearing on Final Offer Arbitration . . . . . . . . . . . . . . . . . .37
17.9 Decision. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37
17.10 Costs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38
(iv)
<PAGE>
17.11 Failure to Participate . . . . . . . . . . . . . . . . . . . . . . .38
17.12 Final Offer Arbitration Procedures . . . . . . . . . . . . . . . . .38
17.13 Continuation of Operations . . . . . . . . . . . . . . . . . . . . .38
ARTICLE 18
GENERAL
18.1 Proper Law. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38
18.2 Attornment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39
18.3 Compliance with Laws, and Regulatory Submissions. . . . . . . . . . . . .39
18.4 Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39
18.5 No Amendment Except in Writing. . . . . . . . . . . . . . . . . . . . . .39
18.6 Entire Agreement. . . . . . . . . . . . . . . . . . . . . . . . . . . . .39
18.7 Further Assurances. . . . . . . . . . . . . . . . . . . . . . . . . . . .39
18.8 Severability. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39
18.9 Alternate Remedies. . . . . . . . . . . . . . . . . . . . . . . . . . . .40
18.10 Waiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40
18.11 Counterpart Execution. . . . . . . . . . . . . . . . . . . . . . . .40
18.12 Confidentiality. . . . . . . . . . . . . . . . . . . . . . . . . . .40
18.13 Equal Opportunity. . . . . . . . . . . . . . . . . . . . . . . . . .40
v
<PAGE>
AMENDED AND RESTATED
NATURAL GAS SALES AGREEMENT
DATED AUGUST 17, 1994
BETWEEN
WESTCOAST GAS SERVICES INC. ("SELLER")
AND
CASCADE NATURAL GAS CORPORATION ("BUYER")
<PAGE>
AMENDED AND RESTATED
NATURAL GAS SALES AGREEMENT
THIS AGREEMENT is made as of August 17, 1994.
BETWEEN:
WESTCOAST GAS SERVICES INC., a body corporate with an office in the
City of Calgary, in the Province of Alberta (herein referred to as
"SELLER")
OF THE FIRST PART
AND
CASCADE NATURAL GAS CORPORATION, a body corporate with an office in
the City of Seattle, in the State of Washington (herein referred to as
"BUYER")
OF THE SECOND PART
WHEREAS, Westcoast Energy, Inc. ("WEI") and Northwest Pipeline
Corporation ("NORTHWEST") are parties to a gas sales agreement dated
September 23, 1960, as amended (the "KINGSGATE GAS SALES AGREEMENT");
AND WHEREAS, Northwest purchased gas under the Kingsgate Gas Sales
Agreement for resale to customers including Buyer;
AND WHEREAS, Seller is the successor by amalgamation to CHMI;
AND WHEREAS, the Kingsgate Gas Sales Agreement has been assigned to
Canadian Hydrocarbons Marketing Inc. ("CHMI") by Westcoast Energy Marketing
Limited ("WEML"), after WEI had assigned it to WEML, and those assignments have
been consented to by Northwest;
AND WHEREAS, pursuant to an Assignment and Amendment of the Kingsgate
Gas Sales Agreement dated September 30, 1991 (the "KINGSGATE ASSIGNMENT"),
Northwest assigned to Buyer a 21.849% share of the Kingsgate Gas Sales Agreement
subject to Northwest's acceptance of a FERC Certificate Order authorizing the
abandonment of Northwest's currently authorized sales service agreements and the
granting of a DOE/OFE approval of, either, the assignment of Northwest's import
authority to Buyer, or Buyer's application for an import authorization;
AND WHEREAS, the conditions in the recital immediately above have now
been satisfied such that the assignment to Buyer has become effective;
AND WHEREAS, the Kingsgate Assignment under Section 9 allowed for the
renegotiation of certain provisions under the Kingsgate Gas Sales Agreement;
AND WHEREAS, pursuant to the implementation of measures by Northwest
in compliance with Order 636 and the related abandonment of Northwest's merchant
sales service function, Buyer and Seller have reached an agreement for the
direct sale of gas from Buyer to Seller, which agreement will replace and
substitute for the Kingsgate Gas Sales Agreement;
NOW THEREFORE, THIS AGREEMENT WITNESSES THAT in consideration of the
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<PAGE>
premises and the mutual covenants and conditions contained in it, the parties
agree as follows:
ARTICLE
DEFINITIONS AND INTERPRETATION
DEFINITIONS
In this Agreement, including the recitals, the following words and
terms shall have the following meanings ascribed thereto:
a. "AAA" shall mean the American Arbitration Association or any successor
thereto;
b. "ANG" means Alberta Natural Gas Company Ltd. or any successor thereto;
c. "ANG TRANSPORTATION AGREEMENT" shall mean the Amending Service Agreement
made and entered into between WEI and ANG dated July 1, 1991, under which
ANG on behalf of WEI agreed to transport through its pipeline facilities on
a firm basis up to 4,523 10(3)m(3) of gas per day;
d. "ANG COMMODITY CHARGES" shall mean the total ANG variable charge amounts,
as more particularly defined and determined in accordance with Section 7.5
below;
e. "ANG COMMODITY RATE" shall mean the variable per unit monthly rate payable
to ANG in respect of the transportation of gas under the ANG Transportation
Agreement, from the Nova Delivery Point to the Delivery Point;
f. "ANG DEMAND CHARGES" shall mean the total demand charge amounts related to
the ANG Transportation Agreement, as more particularly defined and
determined in accordance with Section 7.4 below;
g. "ANG HEATING VALUE" shall mean the average monthly heating value, as
determined by ANG and converted to MMBtu/10(3)m(3), of all gas which is
delivered at the Delivery Point, as that heating value is published by ANG
in its monthly allocation statement;
h. "AFFILIATES" shall mean, in regard to either party, any person directly or
indirectly controlling, controlled by or under common control with the
party; and the term"control" shall mean the possession, directly or
indirectly, of the power to direct or cause the direction of the management
and policies of the person, whether through ownership of voting securities,
by contract or otherwise;
i. "AGREEMENT" shall mean this contract between the parties;
j. "ARBITRAL INSTITUTION" shall mean either the AAA or the BCICAC as
determined pursuant to the provisions of Section 16.2 below, or 17.2 in the
case of Final Offer Arbitration;
k. "BCICAC" shall mean the British Columbia International Commercial
Arbitration Centre or any successor thereto;
l. "BRITISH THERMAL UNIT" or "BTU" shall mean the amount of energy required to
raise the temperature of one pound of distilled water one degree Fahrenheit
(1 DEG.F) from sixty degrees Fahrenheit (60 DEG.F) to sixty-one degrees
Fahrenheit (61 DEG.F) at a constant absolute pressure of fourteen and
seventy-three one hundredths (14.73) pounds per square inch;
m. "BUSINESS DAY" shall mean any day exclusive of Saturdays and Sundays and
days that are statutory or legal holidays under the laws of either the
Province of Alberta or the State of Washington;
2
<PAGE>
n. "CANADIAN REGULATORY AUTHORITIES" shall mean each governmental agency or
other governmental authority in Canada, which now has, or in the future may
have, jurisdiction over the matter in question, relating to the production,
movement, sale, removal or export of gas to be sold and purchased
hereunder, including without limitation, the NEB, the ERCB, the Federal
Governor in Council and the Alberta Minister of Energy;
o. "CONTRACT YEAR" shall mean a period of twelve (12) consecutive months,
beginning at 07:00 hours Pacific Standard Time on November 1st and ending
at 07:00 hours Pacific Standard Time on the November 1st next following,
except the first Contract Year shall mean the period commencing at 0700
hours Pacific Standard Time on the Date of First Delivery and ending on the
next following November 1st;
p. "CONVERTED MONTHLY SALES QUANTITY" shall mean, for calculating the demand
charge payment amounts due for any month, the quantity of gas expressed in
10(3)m(3)'s which Seller sold and delivered to Buyer hereunder during that
month, calculated by dividing the Monthly Sales Quantity by the ANG Heating
Value for that month;
q. "CUBIC FOOT" shall mean that volume of gas which at a temperature of sixty
degrees Fahrenheit (60 DEG.F) and at an absolute pressure of fourteen and
seventy-three hundredths (14.73) pounds per square inch, occupies one (1)
cubic foot of space;
r. "CUBIC METRE" or "M(3)" shall mean that volume of gas which at a
temperature of fifteen degrees Celsius (15 DEG.C) and at an absolute
pressure of one hundred and one and three hundred and twenty-five
thousandths (101.325) kilopascals, occupies one (1) cubic metre of space;
s. "DAILY CONTRACT QUANTITY" or "DCQ" shall mean the daily quantity of gas,
equal to 27,037 MMBtu per day;
t. "DATE OF FIRST DELIVERY" shall mean the day and date upon which the
purchase and sale of gas under this Agreement is to commence, as more
particularly specified under Subsection 11.1 c. below;
u. "DAY" shall mean a period of twenty-four (24) consecutive hours beginning
at the hour, as may be agreed to, from time to time, by ANG and PGT for the
commencement of a day for gas export deliveries to PGT on one day and
ending at the same hour on the following day, which currently is 7:00 a.m.
Pacific Standard Time. The reference for any day shall be the calendar
date upon which the twenty-four hour period shall commence;
v. "DELIVERY POINT" shall mean the point of interconnection between the
pipeline facilities of ANG and PGT located on the international boundary
between British Columbia and the State of Idaho near Kingsgate, British
Columbia;
w. "DOE" shall mean the United States Department of Energy, Office of Fossil
Energy;
x. "ERCB" shall mean the Alberta Energy Resources Conservation Board or any
successor thereto;
y. "EXCHANGE RATE" shall mean the daily spot exchange rate, expressed as
$U.S./$1.00 Cdn., as applicable to the exchange of Canadian dollars for
U.S. dollars, in effect at noon Calgary time, as quoted by the Canadian
Imperial Bank of Commerce, Bow Valley Square 2 Branch, Calgary, Alberta;
z. "FIELD RECEIPT POINTS" shall mean the upstream field receipt points on the
Nova system under the Nova Transportation Agreements, where gas is
3
<PAGE>
delivered into the facilities of Nova;
aa. "FINAL OFFER ARBITRATION" shall mean any arbitration proceedings respecting
the redetermination of the Gas Commodity Price conducted in accordance with
Article 17 below;
bb. "GAS" shall mean natural and/or residue gas which complies with the quality
specifications of ANG for delivery into that pipeline system at the
Delivery Point;
cc. "GAS COMMODITY CHARGES" shall mean the total gas commodity charge amounts
determined in accordance with Section 7.7 below;
dd. "GAS COMMODITY PRICE" shall mean the per unit gas commodity price
determined in accordance with Sections 7.8, or 7.14 below, as applicable;
ee. "GIGAJOULE" or "GJ" shall mean one billion (1,000,000,000) joules;
ff. "GST" shall mean any taxes as provided for in the EXCISE TAX ACT, R.S.C.
1985 c. E-15, as amended or any successor or parallel provincial or
Canadian federal legislation that is intended to impose a tax on the
recipient of goods or services which may be supplied under this Agreement;
gg. "INFLATION INDEX" shall mean the Consumer Price Index published by
Statistics Canada for the period referenced;
hh. "INVOICE DATE" shall mean, for each month, the Business Day which is
closest to the fifteenth (15th) day of that month, and if two Business Days
are equally close to the fifteenth (15th) day of that month the Invoice
Date shall be the earlier Business Day;
ii. "JOULE" or "J" shall mean the amount of work done when the point of
application of a force of one (1) newton is displaced a distance of one (1)
metre in the direction of the force;
jj. "KINGSGATE ADMINISTRATION CHARGES" shall mean the administration charge
amounts determined in accordance with Section 7.11 below;
kk. "KINGSGATE ADMINISTRATION FEE" shall mean the per unit administration fee
amount specified in Section 7.12 below, and recalculated from time to time
in accordance with Section 7.13 below;
ll. "MEGAJOULE" or "MJ" shall mean one million (1,000,000) joules;
mm. "MMBTU" shall mean one million (1,000,000) British thermal units;
nn. "MONTH" shall mean a period commencing at 0700 hours Pacific Standard Time
on the first day of a calendar month and ending at the same time on the
first day of the next succeeding calendar month;
oo. "MONTHLY SALES QUANTITY" shall mean, for any month, the quantity of gas,
expressed in MMBtu's, which Seller sold and delivered to Buyer hereunder
during that month;
pp. "NEB" shall mean the National Energy Board of Canada or any successor
thereto;
qq. "NORTHWEST" shall mean Northwest Pipeline Corporation or any successor
thereto;
rr. "NOVA" shall mean NOVA Corporation of Alberta or any successor thereto;
ss. "NOVA COMMODITY CHARGES" shall mean the total Nova variable charge
4
<PAGE>
amounts, as more particularly defined and determined in accordance with
Section 7.3 below;
tt. "NOVA COMMODITY RATE" shall mean the variable per unit monthly rate payable
to Nova in respect of the transportation of gas under the Nova
Transportation Agreements from the Field Receipt Points to the Nova
Delivery Point;
uu. "NOVA DELIVERY POINT" shall mean the point of interconnection between the
pipeline facilities of Nova and ANG located at or near Coleman, Alberta;
vv. "NOVA DEMAND CHARGES" shall mean the total demand charge amounts related to
the Nova Transportation Agreements, as more particularly defined and
determined in accordance with Section 7.2 below;
ww. "NOVA TRANSPORTATION AGREEMENTS" shall mean the firm receipt point ("FSR")
and non-prorateable delivery point ("FSD") service agreements with Nova,
entered into by Seller, Seller's Suppliers, Pan-Alberta, or suppliers to
any or all of them, which will allow for the firm transportation on the
Nova system from the Field Receipt Points to the Nova Delivery Point of a
daily quantity of gas at least equal to the DCQ;
xx. "PAN-ALBERTA" shall mean Pan-Alberta Gas Ltd. or any successor thereto, as
the principal Seller Supplier as of the date hereof, under the Pan-Alberta
Agreement;
yy. "PAN-ALBERTA AGREEMENT" shall mean the Gas Purchase Agreement between
Seller and Pan-Alberta dated August 17, 1994, under which Seller purchases
gas from Pan-Alberta at the Nova Delivery Point for redelivery to Buyer
under this Agreement;
zz. "PARTY" or "PARTIES" shall, as the context required, mean Seller, or Buyer,
or both of them;
aaa. "PAYMENT DUE DATE" shall mean, for each month, the later of the date which
is ten (10) days following the day on which Buyer receives an invoice in
that month, or the twenty fifth (25th) day of that month, but if either of
those dates is not a Business Day then the Payment Due Date shall be the
Business Day immediately prior to the date;
bbb. "PERSON" shall include an individual, a body corporate, a partnership, an
unincorporated syndicate, an unincorporated organization, an unincorporated
association or a government, or any agency or political subdivision of any
of them;
ccc. "PGT" shall mean Pacific Gas Transmission Company or any successor thereto;
ddd. "PRIME RATE" shall mean the variable rate of interest, expressed as a
percentage per annum, used from time to time by the Canadian Imperial Bank
of Commerce, Bow Valley Square 2 Branch, Calgary, Alberta, as a reference
rate then in effect for determining rates of interest charged on U.S.
dollar commercial loans to customers in Canada;
eee. "PRODUCER SUPPORT AUTHORIZATIONS" shall mean the support and consent
required to be obtained by Seller, or Pan-Alberta, pursuant to the
provisions of the Alberta NATURAL GAS MARKETING ACT S.A. C.N-2.8 or any
successor legislation, for the sale and provincial removal of gas to Seller
and for ultimate resale and delivery of gas by Seller to Buyer under this
Agreement;
fff. "SELLER'S SUPPLIERS" shall mean suppliers of gas to Seller for redelivery
to Buyer under this Agreement, and includes Pan-Alberta under the
provisions of the Pan-Alberta Agreement;
5
<PAGE>
ggg. "SUPPLIER DEMAND CHARGES" shall mean the demand charge amounts determined
in accordance with Section 7.09 below;
hhh. "SUPPLIER DEMAND FEE" shall mean the per unit demand charge amount,
determined in accordance with Section 7.10 below, which is a unitized proxy
for the costs incurred by Seller's Suppliers to construct and operate the
gas gathering and processing facilities, necessary for the continued
deliveries of gas under this Agreement;
iii. "SUPPLY FAILURE" shall mean the failure of Seller to deliver the quantity
of gas nominated by Buyer on any day up to the DCQ, and for which Seller
was obligated to deliver, except to the extent that the failure to deliver
occurred due to an event of Force Majeure as defined in this Agreement, or
due to the suspension of deliveries by Seller as the exercise of Seller's
rights for Buyer's failure to pay, as referenced in subsection 13.4(b)
below;
jjj. "TERM" shall mean the period of time gas is to be purchased and sold under
this Agreement, as specified in Subsection 11.1 b. below;
kkk. "U.S. REGULATORY AUTHORITIES" shall mean each Federal or State governmental
agency or other governmental authority in the United States which now has,
or in the future may have, jurisdiction over the movement, sale,
transportation or import of gas sold and purchased hereunder, including
without limitation, the Federal Energy Regulatory Commission and the DOE;
and
lll. "10(3)M(3)" shall mean one thousand (1,000) cubic metres.
1.2 HEADINGS
The division of this Agreement into Articles, Sections, Subsections
and Paragraphs or any other divisions, and the inclusion of the various
headings, are for convenience of reference only and shall not affect the
interpretation or construction of this Agreement.
1.3 INTERPRETATION
Whenever the singular or masculine or neuter is used in this Agreement
the same shall be construed as meaning plural, or feminine, or body politic, or
corporate and VICE VERSA where the context or the parties hereto so require.
1.4 HEREOF, ETC.
References to "Articles", "Sections", "Subsections" or "Paragraphs"
are references to the Articles, Sections, Subsections and Paragraphs of this
Agreement. Words such as "hereunder", "hereto" and "herein" and similar
expressions shall refer to the whole of this Agreement and not to any particular
Article, Section, Subsection or Paragraph hereof.
1.5 INDUSTRY USAGE
Any word, phrase or expression that is not defined in this Agreement
and that has a generally accepted meaning in the custom and usage in the natural
gas industry in North America shall have that meaning in this Agreement.
1.6 CURRENCY
Unless indicated otherwise, all references to "dollars" or "$" in this
Agreement shall be references to amounts expressed in United States currency.
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ARTICLE 2
LONG TERM AUTHORIZATIONS
2.1 ERCB LONG TERM REMOVAL PERMIT
Seller represents and warrants that Pan-Alberta is the permittee under
long term Gas Removal Permit No. GR87-236 issued by the ERCB, which remains in
full force and effect and in good standing, and authorizes Pan-Alberta to remove
gas from Alberta and sell and deliver it to Seller under the Pan-Alberta
Agreement at the Nova Delivery Point for resale and redelivery to Buyer at the
Delivery Point.
2.2 NEB LONG TERM EXPORT LICENCE
Seller represents and warrants that:
a. it was the licence holder under long term Export Licence No. GL-131 issued
by the NEB which authorized Seller to export gas from Canada at the
Delivery Point under the Kingsgate Gas Sales Agreement;
b. by NEB order No. RO-GL-131 issued January 5, 1994, Export Licence No. GL-
131 has been revoked, and new Export Licence No. GL-226 has been issued to
Seller authorizing Seller to export gas from Canada at the Delivery Point
to Buyer.
2.3 LONG TERM IMPORT AUTHORIZATION
Buyer represents and warrants that it has been granted an assignment
of a pro rata portion of Northwest's rights under DOE long term import
authorization Order No. 664 dated September 9, 1992, which remains in full force
and effect and in good standing and authorizes Buyer to import gas into the
United States at the Delivery Point under the Kingsgate Gas Sales Agreement.
2.4 FURTHER APPLICATIONS
a. Seller represents and warrants that it will make, or cause Pan-Alberta to
make, applications to the ERCB and the Government of Alberta, required to
amend, renew or appropriately replace long term Gas Removal Permit No.
GR87-236, as may be necessary to authorize the sale and removal of gas by
Seller at the Nova Delivery Point for resale and redelivery to Buyer under
this Agreement for the Term.
b. Seller represents and warrants that it will make, or cause to be made,
applications to the NEB and the Government of Canada, required to obtain
any applicable NEB consents related to, or amendments of Export Licence No.
GL-226, as may be necessary to enable the sale and export of gas to be made
to Buyer under this Agreement for the Term.
c. Buyer represents and warrants that it will make applications to the DOE
required to obtain any consents related to, or amendments of, import
authorization Order No. 664, as may be necessary to enable the purchase and
import of gas to be made by Buyer under this Agreement for the Term.
2.5 PRODUCER SUPPORT
a. Buyer and Seller acknowledge that, pursuant to the provisions of the Pan-
Alberta Agreement, Pan-Alberta is required to obtain the requisite long
term producer support for, and the approval of, the sale and removal of gas
to Seller under the Pan-Alberta Agreement for resale to Buyer under this
Agreement.
b. Seller represents and warrants that it will cause Pan-Alberta to make all
requisite submissions to its pool producers, seeking for the Term that
support and approval for the sale and removal of gas to Seller for resale
to Buyer under this Agreement.
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2.6 DILIGENT EFFORTS
Each party shall at its own expense use diligent efforts, to the
extent that it is within its power, to make the applications required by
Sections 2.4 and 2.5 above, and shall keep the other party advised as to their
progress. Seller and Buyer shall cooperate with each other so as to assist each
other in obtaining the required renewed or amended authorizations. Each party
shall, at the request of the other, provide reasonable technical assistance and
support in the preparation of any applications, and shall supply qualified
personnel to provide supportive evidence before any regulatory proceeding in
respect of the subject market and transportation arrangements.
2.7 PRIOR REVIEW
Prior to applying for or amending any long-term certificate, permit,
licence or authorization necessary for the transactions contemplated by this
Agreement, each party shall allow the other party the opportunity to review and
comment on the application if so desired. If a party desiring such review fails
to provide any comments within 15 days of receipt of an application draft, it
shall be deemed to have approved the application text. Any comments received
from a reviewing party within the 15 day period shall be incorporated to the
extent reasonably possible, if in the opinion of the applicant the comments do
not adversely impact upon such application.
2.8 APPROVAL OF AUTHORIZATIONS
Upon receipt by either party, on terms and conditions satisfactory to
the applicant party, of any required renewal or amendment of its respective
long-term certificates, permits, licences or authorizations referred to in
Section 2.4 or Section 2.5, that party (the "TRANSMITTING PARTY") shall promptly
transmit to the other party (the "RECEIVING PARTY") a copy of the applicable
long-term certificate, permit, licence or authorization. If the terms and
conditions of the long-term certificate, permit, licence or authorization are,
for any reason, not satisfactory to the Receiving Party acting reasonably, then
within fifteen (15) days of its receipt the Receiving Party shall so notify the
Transmitting Party, setting forth its reasons for the terms and conditions not
being satisfactory. Failure of the Receiving Party to so respond to the
Transmitting Party shall be deemed to be an acceptance by the Receiving Party of
the subject terms and conditions. Either party's determination as to whether or
not a long-term certificate, permit, licence or authorization or any of its
terms or conditions is satisfactory shall be determined by that party in its
sole discretion, acting reasonably.
2.9 DENIAL OF AUTHORIZATION
If any application made by either party for the renewal or amendment
of a long-term certificate, permit, licence or other authorization referred to
in Section 2.4 or Section 2.5 is denied, that party shall promptly so notify the
other party.
2.10 TERMINATION OF AGREEMENT
If, by November 1, 1994, all long-term authorizations specified in
Sections 2.4 and 2.5 above have not been obtained, then the parties shall use
all reasonable efforts to perform the sale and purchase of gas under this
Agreement pursuant to short term or interim authorizations pending the
obtainment of the last of any outstanding long-term authorization. If, by
January 1, 1995 the last of the outstanding long-term authorizations have not
been obtained, then this Agreement shall terminate, unless the parties agree to
continue the sale of any purchase of gas under this Agreement pursuant to the
subject short term or interim authorizations, which then shall be maintained and
renewed from time to time on a timely basis. In the event of termination of
this Agreement pursuant to this Section 2.10, the parties shall continue to be
bound by the provisions
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of the Kingsgate Gas Sales Agreement, subject to the amendment or renewal of any
authorizations required to be obtained from any applicable Canadian Regulatory
Authorities or U.S. Regulatory Authorities.
2.11 MAINTENANCE OF AUTHORIZATIONS
Subsequent to the obtainment of an authorization, the applicant party
shall use all reasonable efforts to maintain or renew it as applicable, or cause
it to be so maintained and renewed, in good standing and in full force and
effect to enable gas to be purchased and sold for the Term under this Agreement.
ARTICLE 3
TRANSPORTATION MATTERS
3.1 SELLER'S ARRANGEMENTS
Seller hereby represents and warrants to Buyer that:
a. the Nova Transportation Agreements have been entered into which will allow
for the firm transportation on the Nova system to the Nova Delivery Point,
of a daily quantity of gas at least equal to the DCQ; and
b. it is shipper in the first instance, or made sufficient contractual
arrangements with WEI, which will allow for the firm transportation on the
ANG system, from the Nova Delivery Point to the Delivery Point, of a daily
quantity of gas at least equal to the DCQ.
During the Term, Seller agrees to cause Pan-Alberta and Seller's other
Seller's Suppliers to always maintain sufficient Nova firm transportation
service, and Seller agrees to always maintain sufficient ANG firm transportation
service, each of which will allow for the firm transportation of a quantity of
gas at least equal to the DCQ from the Field Receipt Points to the Delivery
Point for the benefit of Buyer.
3.2 BUYER'S ARRANGEMENTS
Buyer hereby represents and warrants to Seller that it has entered
into and will maintain during the Term, firm transportation agreements with PGT
and any other transporters which will allow for the firm transportation from the
Delivery Point to the facilities of Buyer, of a daily quantity of gas at least
equal to the DCQ.
3.3 USE OF SELLER'S TRANSPORTATION ARRANGEMENTS
In the event of a Supply Failure, Buyer shall have the first right to
utilize that portion of the ANG Transportation Agreement and the "FSD" delivery
point portion of the Nova Transportation Agreements in respect to the quantities
which Seller could not supply to Buyer as a result of the Supply Failure, and to
the extent that such utilization is permitted by Canadian Regulatory
Authorities, by ANG, and by Nova, as applicable . The portion which Buyer will
be entitled to utilize on any day during a Supply Failure shall be the
percentage determined in accordance with the following formula:
Percentage of Firm Service = A - B x 100%
-----
Available to Buyer A
WHERE: "A" is the quantity of gas, expressed in MMBtu's, equal to the
quantity that Seller was obligated to deliver on the day, which
was nominated by Buyer on that day;
"B" is the quantity of gas, expressed in MMBtu's supplied by Seller on
that day.
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Buyer shall pay Seller for all ANG and Nova transportation charges associated
with the capacity so utilized by Buyer, including without limitation all demand,
commodity, taxes and fuel gas costs and charges. In determining the amount of
the ANG and Nova transportation charges for which Buyer is to pay Seller, all
ANG and Nova demand charges shall be converted to a pure volumetric amount by
utilizing an assumed load factor of one hundred percent (100%).
3.4 CHANGE IN TRANSPORTATION TOLLS AND TARIFFS
If from time to time the method of determining any applicable Nova or
ANG transportation tolls is changed, or any actual toll, cost or charge amount
under tariff is revised, as finally approved by the government agency having
jurisdiction, then to the extent applicable to the Nova Transportation
Agreements or the ANG Transportation Agreement, as the case may be, the parties
shall make all adjustments to calculations under, or amendments to, this
Agreement, as necessary to incorporate the change or revision. Under the
provisions of Article 7 below, Buyer shall pay for any toll cost or charge
increases and similarly shall be entitled to any toll cost or charge rebates as
billed to Seller by the applicable pipeline whether on a prospective or
retroactive basis, and as finally approved by the government agency having
jurisdiction. However, nothing under this section shall prevent Buyer from
intervening in any agency proceedings and to object to or protest any toll cost
or charge increases ultimately which will be to the account of Buyer under this
Agreement.
3.5 TRANSPORTATION PENALTIES
Any tariff penalties payable to Nova, ANG or PGT for any reason,
including but not limited to a failure to purchase gas nominated or a failure to
supply gas so nominated, shall be borne by the party causing that penalty to be
incurred. If both parties have caused the penalty to be incurred, the penalty
shall be allocated based on each party's proportional share of the causation.
Nothing in this Section 3.5 waives or compromises either party's right to
contest or defend any proposed penalty assessed by Nova, ANG, Northwest or PGT.
ARTICLE 1
QUANTITY OF GAS
4.1 OBLIGATION TO SELL AND DELIVER
Subject to the provisions of this Agreement, Seller represents and
warrants to Buyer that, commencing on the Date of First Delivery and continuing
each day for the Term, Seller will sell and deliver to Buyer on a firm basis, at
the Delivery Point, the quantity of gas which Buyer requests Seller to deliver
on that day up to the DCQ, except if Seller cannot make such deliveries as a
result of a claim of Force Majeure by Seller. Subject to the provisions of this
Agreement, Buyer agrees to purchase from Seller on a firm basis the quantities
of gas so nominated and received by Buyer and delivered by Seller at the
Delivery Point.
4.2 NOMINATIONS
a. Buyer shall provide a notice to PGT of its nomination of the quantity of
gas which PGT, on behalf of Buyer, will request ANG, on behalf of Seller,
to deliver on any day under this Agreement. Subject to tariff minimum
notice requirements, a nomination received at least two (2) hours prior to
the time at which final nominations are accepted by ANG on the day prior to
the specified day the nomination is to be effective shall be a valid and
applicable nomination for that specified day. A nomination not received as
above shall be effective at the commencement of the day next following the
specified day. Nominations may be delivered orally and subsequently
confirmed by written notice.
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b. Any quantity nominated for purchase by Buyer for any particular day shall
remain the standing nomination of the quantity of gas to be requested by
Buyer on subsequent days until the nomination is changed by Buyer pursuant
to subsection 4.2(a) above.
4.3 MINIMUM PURCHASE QUANTITY
a. During the period from August 17, 1994 to November 1, 1994, and for each
Contract Year commencing on November 1, 1994, Buyer shall purchase from
Seller at the Delivery Point, or if not purchased and taken, shall
nevertheless pay for at the Gas Commodity Price specified in Section 7.10
as in effect on the last day of the period, a minimum quantity of gas which
shall be equal to:
(i) 865,184 MMBtu, for the August 17, 1994 to November 1, 1994
period; and
(ii) 4,136,661 MMBtu for each subsequent Contract Year during the Term.
b. The positive difference, if any, between the minimum quantity specified in
each clause of Subsection (a) above and the quantity actually purchased and
taken by Buyer during the specified period shall be paid for by Buyer
within sixty (60) days following the last day of the specified period, at
the Gas Commodity Price as in effect on the last day of that period.
ARTICLE 5
QUALITY AND MEASUREMENT
5.1 ANG QUALITY AND PRESSURE STANDARDS
The gas to be delivered hereunder shall meet or exceed all gas quality
standards of ANG for gas delivered at the Delivery Point, including without
limitation, minimum heating value, delivery pressure, temperature, and all other
similar quality standards and specifications as set out in ANG's tariff, as
amended from time to time.
5.2 DELIVERY IN A COMMON STREAM
Buyer and Seller each recognize that the gas to be sold and purchased
at the Delivery Point will be from a commingled stream of gas being transported
on the pipeline system facilities of Nova and ANG, for redelivery in to the PGT
pipeline system.
5.3 ANG MEASUREMENTS
All gas to be delivered hereunder shall be measured as to volume,
quality, total number of MMBtu and heating value by ANG in accordance with the
provisions set out in its tariff, as amended from time to time, at the meters
installed, operated and maintained by ANG at the Delivery Point. The heating
value of the delivered gas shall be the ANG Heating Value, determined by the
instruments operated by ANG. These measurements and all other volume, quality
and heating value measurements as made by ANG shall be final and binding upon
the parties and utilized for all purposes of this Agreement.
5.4 MEASUREMENT STANDARDS
The standards of measurement and the meter testing procedures shall be
those of ANG as set out in its tariff, as amended from time to time. Upon the
request of Buyer, Seller shall exercise its rights under the ANG Transportation
Agreement to witness tests to be conducted by ANG to verify the accuracy of
ANG's measuring equipment, or to request ANG to conduct tests to verify the
accuracy of such equipment. Buyer shall reimburse Seller for any
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<PAGE>
expense associated with such request to the extent that Seller is obligated to
reimburse ANG. Upon the request of Buyer, Seller shall request of ANG that a
representative of Buyer be allowed to witness any such tests.
5.5 UNIT CONVERSIONS
All conversions to be done for or any way in relation to this
Agreement from Imperial units of measurement to metric units or VICE VERSA,
shall be done utilizing the conversions utilized by ANG, from time to time which
have been agreed upon between ANG and PGT as conversions applicable to
deliveries from ANG to PGT at the Delivery Point. Such conversions as provided
for in the ANG tariff shall include the conversion from MMBtu units to 10(3)m(3)
units for the purpose of determining the Converted Monthly Contract Quantity and
the related demand charge payment calculations under this Agreement.
ARTICLE 6
POSSESSION, TITLE AND WARRANTY
6.1 TRANSFER OF TITLE
Delivery of gas by Seller to Buyer shall be at the Delivery Point.
Possession and title to the gas so delivered shall pass from Seller to Buyer at
the Delivery Point. Seller shall be responsible for making all arrangements
necessary to transport and deliver gas to the Delivery Point and Buyer will be
responsible for making all arrangements necessary to receive and transport gas
from the Delivery Point. Other than as contemplated herein, all costs and
expenses of delivering the gas to the Delivery Point shall be paid by Seller and
all costs and expenses of transporting the gas beyond the Delivery Point shall
be borne by Buyer.
6.2 RISK
As between the parties, Seller shall be deemed to be in exclusive
control and possession of the gas to be sold hereunder and responsible for any
loss, damage or injury caused thereby until the gas is delivered at the Delivery
Point, at which time and point Buyer shall be deemed to be in exclusive control
and possession of the gas and thereafter responsible for any loss, damage or
injury caused by it.
6.3 TITLE AND INDEMNITY
Seller hereby warrants and represents to Buyer that, at the point
where title is to pass to Buyer, Seller shall have a legal or equitable right to
all gas to be sold hereunder and shall sell gas to Buyer at that point free and
clear of all liens, encumbrances and adverse claims whatsoever. Seller agrees
to indemnify Buyer and save it harmless from all suits, claims, actions, debts,
accounts, costs, losses, expenses or damages arising from or out of any adverse
claims by any or all persons to the gas delivered hereunder which relate to
matters occurring prior to possession and title to the gas passing to Buyer.
Buyer agrees to indemnify Seller and save it harmless against all suits, claims,
actions, debts, accounts, costs, losses, expenses or damages arising from or out
of any adverse claims by any or all persons to the gas which relate to matters
occurring after possession and title to the gas passes to Buyer.
ARTICLE 7
GAS SALES REVENUES
7.1 TOTAL AMOUNTS TO BE PAID TO SELLER
The total amounts for a month to be paid by Buyer to Seller for the
quantity of gas sold and delivered by Seller to Buyer under this Agreement for
the immediately preceding month shall be the sum of: the Nova Demand Charges,
the ANG Demand Charges, the Nova Commodity Charges, the ANG Commodity Charges,
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the Gas Commodity Charges, the Supplier Demand Charges and the Kingsgate
Administration Charges, all of which are set forth in this Article.
7.2 NOVA DEMAND CHARGES
The transportation service monthly demand charges amounts to be paid
by Buyer to Seller in respect of the Nova Transportation Agreements (the "NOVA
DEMAND CHARGES") shall be equal to the sum of:
i. the quantity of receipt point ("FSR") contract demand capacity, equal
to the Daily Contract Quantity, multiplied by one hundred and forty
percent (140%), multiplied by the Nova receipt point ("FSR") firm
service monthly demand charge calculated under Nova's toll schedules
of its tariff, as amended from time to time (the "NOVA TOLL
SCHEDULE"); plus
ii. the quantity of delivery point ("FSD") contract demand capacity, equal
to the Daily Contract Quantity, multiplied by the Nova delivery point
("FSD") firm service monthly demand charge calculated under the Nova
Toll Schedule.
7.3 NOVA COMMODITY CHARGES
The transportation service monthly commodity charge amounts to be paid
by Buyer to Seller in respect of the Nova Transportation Agreements (the "NOVA
COMMODITY CHARGES") shall be equal to the Nova Commodity Rate multiplied by the
Converted Monthly Sales Quantity.
7.4 ANG DEMAND CHARGES
The transportation service monthly demand charge amounts to be paid by
Buyer to Seller in respect of the ANG Transportation Agreement (the "ANG DEMAND
CHARGES") shall be equal to the product of the monthly demand charge calculated
under the ANG rates and charges schedules of its tariff multiplied by the Daily
Contract Quantity.
7.5 ANG COMMODITY CHARGES
The transportation service monthly commodity charge amounts to be paid
by Buyer to Seller in respect of the ANG Transportation Agreement (the "ANG
COMMODITY CHARGES") shall be equal to the ANG Commodity Rate multiplied by the
Converted Monthly Sales Quantity.
7.6 DEMAND CHARGES PAYMENT
Subject to the provisions of this Agreement, the Nova Demand Charges,
the Supplier Demand Charges and the ANG Demand Charges are to be paid each
month, regardless of whether or not Buyer is nominating or has nominated gas
under this Agreement for the month, and regardless of whether or not the reason
for which Buyer is or has not so nominated is due to an event of Force Majeure
as claimed by Buyer.
7.7 GAS COMMODITY CHARGES
The Gas Commodity Charges, to be paid each month, shall be an amount
determined in accordance with the following formula:
Gas Gas x Monthly
Commodity = Commodity Sales
Charges Price Quantity
7.8 GAS COMMODITY PRICE
a. The Gas Commodity Price to be paid for gas delivered each month of the
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period commencing on the Date of First Delivery and expiring on October 31,
1995 shall be calculated as a percentage price determined under Subsection
c below, of the arithmetic average of the published index prices for the
month (the "Index Price") for deliveries of gas from the "ROCKY MOUNTAIN"
and "CANADIAN BORDER" designated supply sources into the Northwest pipeline
system, as those prices are provided in the publication entitled, "INSIDE
F.E.R.C.'S GAS MARKET REPORT" in the table entitled, "PRICES OF SPOT GAS
DELIVERED TO PIPELINES.......(per MMBtu dry), under the "NORTHWEST PIPELINE
CORP" ENTRY.
b. The reference publication issue to determine the Gas Commodity Price for a
month shall be the first issue which is published after the first day of
the month.
c. The percentage of the Index Price shall be determined based on the quantity
of gas purchased by Buyer under this Agreement during a specified period,
in accordance with the following table.
[CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]
7.9 SUPPLIER DEMAND CHARGES
The Supplier Demand Charges for each month, commencing with the month
of the Date of First Delivery, shall be determined in accordance with the
following formula:
Supplier Demand Charges = Supplier Demand Fee x [number of days in the
month] x DCQ
7.10 SUPPLIER DEMAND FEE
The Supplier Demand Fee shall be an amount equal to ten cents per
MMBtu ($0.10/MMBtu). For each subsequent Contract Year, the Supplier Demand Fee
shall be increased by the percentage amount of the Inflation Index applicable
for the immediately preceding Contract Year.
7.11 KINGSGATE ADMINISTRATION CHARGES
The Kingsgate Administration Charges, for each month, shall be an
amount determined in accordance with the following formula:
Kingsgate Administration Charge = Kingsgate Administration Fee x
Monthly Sales Quantity
7.12 KINGSGATE ADMINISTRATION FEE
The Kingsgate Administration Fee for the period commencing on the Date
of First Delivery and expiring on October 31, 1997 shall be [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]. The Kingsgate
Administration Fee for the five (5) year period commencing November 1, 1997 and
for the two (2) year period commencing November 1, 2002 shall be expressed in
$U.S./MMBtu and shall be determined in accordance with Section 7.13 below.
7.13 REDETERMINATION OF KINGSGATE ADMINISTRATION FEE
The Kingsgate Administration Fee shall be recalculated in accordance
with the following:
a. for the period November 1, 1997 to October 31, 2002:
Kingsgate Administration Fee = [CONFIDENTIAL INFORMATION OMITTED AND
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FILED SEPARATELY WITH THE COMMISSION] x A
---
B
WHERE: "A" is the sum of the Inflation Index applicable to each month in
the period November 1, 1992 to September 1, 1997, divided by the
number of months in that period;
WHERE: "B" is the Inflation Index for the month of the Date of First
Delivery.
b. for the period November 1, 2002 to October 31, 2004:
Kingsgate Administration Fee = Kingsgate Administration Fee
calculated under x C
Subsection (a) above D
WHERE: "C" is the sum of the Inflation Index applicable to each month in
the period November 1, 1997 to September 1, 2002 divided by the
sum of months in that period;
WHERE: "D" is the Inflation Index for November 1997.
7.14 REDETERMINATION OF GAS COMMODITY PRICE
a. Buyer and Seller shall commence negotiations, on or before July 1st in each
Contract Year, other than the first Contract Year, and attempt, in good
faith, to reach agreement as to a redetermined Gas Commodity Price to apply
for gas to be delivered during the Contract Year commencing the immediately
following November 1st. Seller may request that Pan-Alberta or any other
Seller Supplier be a party to the negotiations and Buyer shall consent to
that request, to the extent that it is fair and reasonable. The parties
shall attempt to agree on a Gas Commodity Price which reflects the
following "PRICING CRITERIA":
THE GAS COMMODITY PRICE, EXPRESSED IN $U.S. PER MMBTU,
SHALL BE REDETERMINED AT A LEVEL WHICH WILL REASONABLY
ENSURE THAT THE TOTAL DELIVERED PRICE OF GAS UNDER THIS
AGREEMENT SHALL REMAIN REASONABLY EQUIVALENT TO THE TOTAL
DELIVERED PRICES TO BE PAID EFFECTIVE THE FOLLOWING
NOVEMBER 1 FOR OTHER SUPPLIES OF NATURAL GAS WHICH ARE
BEING SOLD AND DELIVERED OFF THE NORTHWEST AND/OR PGT
SYSTEMS TO PURCHASERS WHICH ARE LOCAL DISTRIBUTION
UTILITIES IN THE STATES OF WASHINGTON AND OREGON BY EITHER
PIPELINE COMPANIES OR DIRECT SELLERS; PROVIDED THAT, SUCH
REASONABLY EQUIVALENT PRICES MUST BE PAID PURSUANT TO
CONTRACTS WHICH HAVE TERMS AND CONDITIONS SUBSTANTIALLY
SIMILAR TO THE TERMS AND CONDITIONS OF THIS AGREEMENT,
INCLUDING WITHOUT LIMITATION PROVISIONS SUCH AS QUANTITY,
INITIAL TERM LENGTH AND LOAD FACTOR. FOR THE PURPOSES OF
RELEVANT COMPARISON, ANY REASONABLY EQUIVALENT PRICE IN A
COMPARATIVE CONTRACT MUST BE ADJUSTED AS WARRANTED TO TAKE
INTO ACCOUNT THE PROVISION DIFFERENCES, IF ANY, BETWEEN
THAT CONTRACT AND THIS AGREEMENT.
b. If the parties reach agreement as to a redetermined Gas Commodity Price,
and document their agreement in a letter executed by both parties by the
August 1st immediately following the commencement of negotiations, then
subject to Section 7.15 below, the redetermined Gas Commodity Price shall
apply throughout the Contract Year commencing the following November 1.
If the parties have not documented their agreement as to a redetermined
Gas Commodity Price in a letter executed by both parties by the August
1st date, or the requisite producer support referred to in Section 7.15
below is not obtained by the following September 1st, then no later than
the following November 1st either party may invoke
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Final Offer Arbitration pursuant to Article 17 to determine the
appropriate Gas Commodity Price for the Contract Year commencing the
following November 1st.
c. If the Final Offer Arbitration procedure is so invoked, but not completed
by the November 1st deadline, then the same Gas Commodity Price which was
in effect during the previous Contract Year shall continue in effect
until such time as the Final Offer Arbitration decision is rendered.
Upon such decision being rendered, the redetermined Gas Commodity Price
set out in the Final Offer Arbitration decision shall be effective as of
the first day of the month following the date of the decision and the
parties shall make all appropriate adjustments to reflect the nature of
that decision, including appropriate amendments to this Agreement.
d. If the Final Offer Arbitration procedure is not invoked prior to the
November 1st immediately following the commencement of negotiations then
the Gas Commodity Price which was in effect for the previous Contract
Year shall continue in effect throughout the Contract Year commencing
such November 1st.
7.15 REQUISITE PRODUCER SUPPORT
a. Buyer acknowledges and agrees that the effective November 1st
implementation of a redetermined Gas Commodity Price for a Contract Year
is first subject to Seller or Pan-Alberta, as the case may be, obtaining
the requisite Producer Support Authorizations for, and approval of, the
continued sale and removal of gas to Seller under Pan-Alberta Agreement
for resale to Buyer under this Agreement. Promptly upon the
documentation of the agreement as to a redetermined Gas Commodity Price,
Seller shall, with all due diligence and reasonable efforts, cause Pan-
Alberta to obtain the requisite Producer Support Authorizations, no later
than the following September 1st.
b. If the requisite Producer Support Authorizations are not obtained, then
either Buyer or Seller may invoke the Final Offer Arbitration procedure
and Seller, Pan-Alberta and Pan- Alberta's participating pool producers
shall be bound by and shall deliver gas under the redetermined Gas
Commodity Price set out in the Final Offer Arbitration decision.
ARTICLE 8
SECURITY OF SUPPLY
8.1 SOURCE OF GAS SUPPLY
Although Seller contemplates that the gas to be delivered
hereunder shall be purchased by it pursuant to the Pan-Alberta Agreement and
other Seller's Supplier contracts, Seller may supply gas to Buyer under this
Agreement which originates from any sources without prior notice to and at no
additional cost to Buyer.
ARTICLE 9
SUPPLY FAILURE
INDEMNITY AND MITIGATION
9.1 NOTICE OF SUPPLY FAILURE AND SELLER MITIGATION EFFORTS
If, on any day a Supply Failure occurs, then Seller immediately
shall provide notice of the Supply Failure to Buyer. Seller shall also employ
commercially reasonable efforts to secure alternate supplies of gas from
sources, other than Seller's Supplier contracts, in order to mitigate the Supply
Failure, and shall bear the additional costs of obtaining that replacement gas
if so obtained. In the event and to the extent that Seller is unsuccessful in
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obtaining those alternate supplies, then Buyer may obtain gas from other
sources, and the provision of Section 9.2 below shall apply.
9.2 SELLER'S DELIVERY FAILURE INDEMNITY
If, on any day a Supply Failure occurs, then, subject to Section
9.1 above, Buyer shall have the right to purchase the shortfall in the delivery
of gas from other sources. If Buyer obtains gas from other sources to replace
Supply Failure quantity on that day, then Seller agrees to indemnify Buyer for
all of Buyer's reasonable incremental direct costs which it incurs in respect of
Buyer purchasing such replacement quantities of gas from other sources, rather
than purchasing such gas from Seller pursuant to this Agreement. Such
incremental costs of Buyer shall include the reasonable incremental cost of
obtaining and transporting the gas quantity which Buyer procures in lieu of the
Supply Failure gas quantity. However, Seller shall only be required to
indemnify Buyer:
i. for a maximum of [CONFIDENTIAL INFORMATION OMITTED AND FILED
SEPARATELY WITH THE COMMISSION] of daily Supply Failures,
commencing on the day an initial Supply Failure event has
occurred; and
ii. in any event, for a cumulative maximum of [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION] days
of daily Supply Failures during any one Contract Year.
After the indemnity period has expired, Buyer may exercise its
termination rights under Section 9.5 in accordance with the provisions of that
Section.
9.3 BUYER TO MITIGATE
Buyer shall use all reasonable efforts to mitigate any incremental
costs and expenses which Seller is obligated to indemnify Buyer for pursuant to
this Article, and should Buyer elect to purchase replacement gas Buyer shall
attempt to find replacement gas with the lowest cost.
9.4 [CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE
COMMISSION]
9.5 TERMINATION RIGHTS FOR EXTENDED SUPPLY FAILURE
In the event during a Contract Year:
i. A Supply Failure occurs on any day, whereby the Supply Failure was
such that Seller failed to deliver at least [CONFIDENTIAL
INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION] of
the quantity nominated by Buyer on that day; and
ii. such Supply Failures have occurred on days during a Contract Year
for either a period equal to a total of:
a. [CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH
THE COMMISSION]
b. [CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH
THE COMMISSION]
then in addition to its indemnification rights under Section 9.2,
Buyer may, no later than thirty (30) days following the last day
of the applicable period, give notice to the Seller that Buyer is
electing to terminate this Agreement on thirty (30) days' prior
notice, and this Agreement then shall terminate at the expiry of
that notice period. Upon that termination, Seller shall have no
further liability to Buyer under this Agreement except as
expressly so stated, and particularly as so stated for
indemnifying Buyer as set forth
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in this Article for the Supply Failures during the Supply Failure
period.
9.6 NOTICE OF ANTICIPATED SUPPLY FAILURE
If, at any time during the Term, Seller becomes aware of any
circumstance or matter by which it expects a Supply Failure to arise, then
Seller shall use reasonable efforts to provide Buyer with prior notice of the
anticipated Supply Failure as soon as is reasonably possible under the
circumstances.
9.7 DCQ REDUCTION RIGHTS FOR EXTENDED SUPPLY FAILURE
a. In the event during a Contract Year a Supply Failure occurs on any day or
days, whereby the Supply Failure is such that Seller fails to deliver at
least eighty percent (80%) of the quantity nominated by Buyer on the days
in question, then Buyer may reduce the DCQ by written notice to Seller.
b. To effect a DCQ reduction, the written notice must be served no later
than ten (10) days after the expiry of a [CONFIDENTIAL INFORMATION
OMITTED AND FILED SEPARATELY WITH THE COMMISSION] day period which
commences on the first day that a Supply Failure occurs. The
[CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE
COMMISSION] day period first must expire before notice may be served.
c. The DCQ reduction amount shall be no greater than the amount determined
by the following formula:
Maximum Amount = A
of DCQ Reduction [CONFIDENTIAL INFORMATION OMITTED AND
FILED SEPARATELY WITH THE COMMISSION]
WHERE: "A" is the total quantity of gas, expressed in MMBtu, that was
nominated by Buyer during the [CONFIDENTIAL INFORMATION OMITTED
AND FILED SEPARATELY WITH THE COMMISSION] day period, but was not
delivered by Seller due to the Supply Failures occurring during
that period.
9.8 DEMAND CHARGE REDUCTION UPON SUPPLY FAILURE
a. The ANG Demand Charges, Nova Demand Charges and Supplier Demand Charges
for any month will be reduced if for any day during that month:
i. a Supply Failure has occurred; or
ii. A period of Force Majeure under Article 12 is in effect as
declared by Seller, for any reason other than due to the
curtailment, stoppage or pro-ration of firm service under the ANG
Transportation Agreement or the Nova Transportation Agreements, as
applicable.
b. If either event occurs, the ANG Demand Charges, Nova Demand Charges and
Supplier Demand Charges, for the month will be reduced by an amount
determined as follows:
Demand Charges Reduction = Demand Charges x
[CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION]
where: "DEMAND CHARGES" is the total amount of ANG Demand Charges,
Nova Demand Charges and Supplier Demand Charges payable for
the month under this Agreement;
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where: "A" is the sum of the daily quantities of gas, expressed in
MMBtu's, which Buyer nominated on the day or days in
question in accordance with this Agreement, but which
Seller failed to deliver due to either event set out in
Subsection (a) above;
where: "B" is the number of days in the month.
c. The invoice for the month to be delivered by Seller in accordance with
Article 13 below shall include an itemization of any demand charges
reduction amounts to be credited to Buyer under this Section.
9.9 LIMITATION ON SELLER'S LIABILITY
Buyer agrees that Seller's liability, whether in contract or tort
or otherwise, for any Supply Failure shall be limited to the indemnities set out
in Section 9.2 and the rights set forth in this Article, and Buyer's remedies
for any such Supply Failure shall be limited to the aforesaid indemnities and
rights.
9.10 LIMITATION ON PARTIES' LIABILITIES
Except for Buyer's direct incremental costs incurred in purchasing
replacement quantities of gas as set out in Section 9.2, or any other direct
costs as specifically set forth as liquidated damages and indemnity amounts
under this Agreement, neither party be liable to the other party for any
indirect, consequential, punitive or special losses, damages or expenses of any
nature whatsoever, that may be incurred by the other party, including without
limitation, the loss of profits or income, the loss of business expectations,
business interruptions, the loss of a party's contracts with any third party or
any damage to third parties (except for obligations to Nova, ANG or PGT provided
hereunder) arising in any way out of this Agreement or any breach thereof.
ARTICLE 10
TAXES
10.1 PAYMENT OF TAXES
a. Seller shall pay or cause to be paid all royalties and all business
transfer, severance, sales, value added, excise, GST and all other
similar taxes, levies, assessments and charges that are validly exigible
on the gas delivered or to be delivered hereunder prior to the sale of
the gas at the Delivery Point.
b. Buyer shall pay or cause to be paid all such taxes, levies, assessments
and charges that are validly exigible on the gas after the sale thereof
at the Delivery Point.
c. In the event that any new tax, levy, assessment or charge is imposed on
either party at the Delivery Point or in the event that the amount of any
existing tax, levy, assessment or charge is increased (a "BORDER CHARGE")
then either party may, within thirty (30) days of the effective date of
the imposition of such Border Charge request that the Gas Commodity Price
be renegotiated. The party requesting a renegotiation (the "PROPOSER")
shall set out in a notice (the "BORDER CHARGE NOTICE") to the other party
(the "RECIPIENT") full details of the Border Charge as well as the
adjustment to the current Gas Commodity Price which, in the Proposer's
view, is appropriate to reflect the imposition of the Border Charge.
d. Upon receipt of the Border Charge Notice the parties shall commence
negotiations to determine what adjustment to the Gas Commodity Price may
be appropriate. If the parties are unable to reach agreement within
thirty (30) days of the receipt of the Border Charge Notice then either
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party may submit for arbitration pursuant to Article 16 the issue of what
is an appropriate adjustment to the Gas Commodity Price to be made as a
result of the imposition of the Border Charge which will be fair and
equitable to both parties considering all relevant factors and
circumstances. In the event that the arbitration decision indicates that
an adjustment to the Gas Commodity Price is appropriate then the
effective date of such adjustment shall be the date of the Recipient's
receipt of the Border Charge Notice.
10.2 PRICES EXCLUSIVE OF TAXES
All dollar amounts stated in this Agreement and all amounts
payable by Buyer under it are exclusive of any tax, levy or duty which may be
imposed by any Federal or Provincial legislation, and which is required to be
paid or collected by Seller which, without limiting the generality of the
foregoing, shall include GST.
10.3 GOODS AND SERVICES TAX
Buyer shall provide Seller with all appropriate authorizations and
declarations as required so that the sale of gas may be zero-rated for GST
purposes, if that rating is applicable to the sale of gas from Seller to Buyer.
ARTICLE II
TERM OF AGREEMENT
11.1 TERM
a. This Agreement shall become effective as of August 17, 1994.
b. The term of the purchase and sale of gas under this Agreement (the
"TERM") shall commence on the Date of First Delivery, and continue in
effect until October 31st, 2004, and after that date from Contract Year
to Contract Year, unless on October 31st, 2003 or any subsequent November
1st, either party gives the other party no less than twelve (12) months
advance written notice of termination, to be effective on the immediately
following November 1st, in which case the Term shall expire on that
immediately following November 1st.
c. The Date of First Delivery shall be the later of August 17, 1994 and the
date all authorizations under Sections 2.4 and 2.5 above are obtained.
The parties anticipate the requisite producer support set out in Section
2.5 above will be obtained on an interim basis on August 17, 1994. If
that occurs, the parties may commence the purchase and sale of gas under
this Agreement using interim short term regulatory authorizations pending
receipt of the authorizations referred to in Article 2.
11.2 EFFECT OF TERMINATION
Notwithstanding the termination of this Agreement pursuant its
provisions, any provisions respecting liabilities and indemnities which have
accrued prior to the date of termination, and provisions which are specifically
stated to survive the termination of the Agreement shall continue in full force
and effect in accordance with their terms. The parties shall use their
reasonable efforts to make all adjustments and settle all accounts which are
outstanding between the parties as of the date of termination as soon as
possible.
ARTICLE 12
FORCE MAJEURE
12.1 SUSPENSION
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Subject to all other provisions of this Article 12, if either
party is rendered unable by reason of a substantiated event of Force Majeure to
perform in whole or in part any obligation or covenant set forth in this
Agreement, with the exception of unpaid financial obligations, such failure
shall be deemed not to be a breach of the particular obligation or covenant in
question. The obligations of both parties under this Agreement shall be
suspended to the extent directly affected and necessary during the continuation
of the inability so caused by the Force Majeure event.
12.2 DEFINITION OF FORCE MAJEURE
For the purpose of this Agreement, the term "FORCE MAJEURE" shall
mean: (i) any acts of God, including lightning, earthquakes, storms, washouts,
landslides, fires, epidemics and floods; (ii) strikes, lockouts or other
industrial disturbances; (iii) acts of the enemies of the State of a party,
sabotage, wars, blockades, insurrections, riots, civil disturbances or arrests
and restraints of rulers; (iv) fires, explosions, nuclear and radiation activity
or fall out; (v) breakages of, hydrate obstructions of or accidents to,
machinery or lines of pipe; (vi) inability to obtain materials, supplies,
permits or labour; (vii) freezing of wells or delivery facilities or well
blowouts; (viii) the laws, orders, rules, regulations, acts, or restraints of
any court or governmental or regulatory authority, including the revocation or a
materially adverse amendment to any permit, authorization or approval of any
governmental or regulatory authority required to perform or comply with any
obligation or condition of this Agreement, unless the revocation or amendment
was caused by the negligence or violation of the terms thereof by the party
claiming an event of Force Majeure; (ix) the failure of Seller's Supplier to
deliver gas to Seller where the failure occurs as a result of any event or
occurrence of the character defined in this Section as a Force Majeure event;
(x) the curtailment, stoppage or pro-ration of firm transportation service on
Nova, ANG or PGT, whether or not NOVA, ANG or PGT is claiming an event of Force
Majeure under the applicable service agreement; (xi) the failure on the part of
a customer of Buyer to purchase substantial quantities of gas from Buyer as a
direct result of any event or occurrence of the character defined in this
Section as a Force Majeure event; (xii) or any other causes, whether of the kind
stated above or otherwise, and not within the control of the party claiming
suspension and which, by the exercise of due diligence, that party is unable to
overcome. For the purposes of this Article 12, a party is deemed to have
control over the actions or omissions of those persons for which it, its agents,
contractors or employees have delegated, assigned or subcontracted its
obligations and responsibilities.
12.2 EXCEPTIONS
Neither party shall be entitled to the benefit of the provisions
of this Article under any of the following circumstances:
a. to the extent that the failure was caused by the negligence or breach of
contract of the party claiming suspension;
b. to the extent that the failure was caused by the party claiming
suspension having failed to diligently attempt to remedy the condition by
taking all reasonable acts and to resume the performance of such
covenants or obligations with reasonable dispatch;
c. if the failure was caused by lack of funds or is in respect to the
payment of any amount due under this Agreement;
d. unless, as soon as possible after the happening of the Force Majeure
event, or as soon as possible after determining that the occurrence was
in the nature of Force Majeure and would affect the claiming party's
ability to observe or perform any of its covenants or obligations under
this Agreement, the party claiming suspension gives to the other party
notice to the effect that the claiming party is unable, by reason of a
particular specified event of Force Majeure to perform the particular
covenants or obligations;
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e. to the extent the failure was due to an event or situation whereby the
claiming party does not perform because continued performance would be
economically disadvantageous or unprofitable, or because the claiming
party has opportunities to deliver or purchase gas, as the case may be,
under more attractive pricing terms as offered by third parties.
12.4 RESUMPTION OF OBLIGATIONS
The party claiming suspension shall give notice to the other
party, as soon as possible after the Force Majeure condition is remedied, to the
effect that it has been remedied and that the claiming party has resumed, or is
then in a position to resume, the performance of the subject covenants and
obligations either in whole or in part.
12.5 SETTLEMENT OF INDUSTRIAL DISPUTES
Notwithstanding anything to the contrary in this Article 12,
expressed or implied, the settlement of strikes, lockouts and other industrial
disturbances shall be entirely within the discretion of the claiming party so
involved, and that party may make settlement at a time and on terms and
conditions as it may deem to be advisable. No delay in making the settlement
shall deprive the claiming party of the benefit of its right to claim Force
Majeure under this Agreement.
12.6 EFFECT ON DEMAND CHARGE PAYMENT OBLIGATIONS
a. Notwithstanding anything to the contrary in this Article 12, but subject
to its provisions and to the provisions of Section 9.8, any claim of
Force Majeure by Buyer shall not in any way affect or reduce Buyer's
obligation to pay the Nova Demand Charges, the ANG Demand Charges and the
Supplier Demand Charges. If Buyer claims a Force Majeure, then Seller
shall use its reasonable efforts to mitigate for Buyer the portion of the
Nova Demand Charges and the ANG Demand Charges which is attributable to
the quantities not taken during any month as a result of Buyer's claim of
Force Majeure.
b. To the extent that during the Force Majeure period Seller is successful
in mitigating the demand charge payment obligations of Buyer by utilizing
any of the subject ANG and Nova transportation capacity which otherwise
would have been unused as a result of Buyer's Force Majeure claim, then
Buyer shall be allocated a credit amount. The credit amount, if any, for
a month during which the Force Majeure event occurred, shall be equal to
the sum of the Daily Usage Credits for certain days of that month,
determined for each day in accordance with the following formula:
"Daily Usage Credits = A x B
-------------------
Number of Days
in the month
WHERE: "A" shall mean the quantity of gas, expressed in 10(3)m(3), owned
or controlled by Seller which was transported by Seller under the
ANG Transportation Agreement and the Nova Transportation
Agreements capacity on a day which Buyer declared Force Majeure,
and which capacity otherwise would have been used to transport the
quantity of gas to be purchased by Buyer but for the Force Majeure
claim by Buyer;
"B" shall mean the sum of the ANG Demand Charges and the Nova
Demand Charges, allocable to the daily quantity deemed to have
been nominated by Buyer, which quantity is equal to the arithmetic
average daily quantity of gas nominated by Buyer under this
Agreement for the full month immediately prior to the commencement
of the Force Majeure period.
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For greater certainty, no Daily Usage Credits shall apply if Buyer is not
taking gas for any reason other than an event of Force Majeure as first
claimed by Buyer.
c. If during a month Seller or a Seller's Supplier:
i. declares Force Majeure due to the curtailment, stoppage or
proration of Nova or ANG firm service under the ANG Transportation
Agreement or the Nova Transportation Agreements, as applicable;
and
ii. is entitled to receive a form of contractual or tariff credit from
the pipeline because of the pipeline's non-performance during the
Force Majeure period, which credit is to be applied against the
obligation to pay the demand charges as shipper under the
applicable firm service agreement;
then Seller shall allocate to Buyer an amount equal to the total credit
so received, to be applied against Buyer's ANG Demand Charges and Nova
Demand Charges payment obligations under this Agreement for that Month.
12.7 TERMINATION FOR EXTENDED FORCE MAJEURE PERIOD
If for any Contract Year either party claims an event of Force
Majeure which results in the total suspension of gas deliveries, or receipts, as
applicable for either a period equal to a total of:
i. forty-five (45) consecutive days; or
ii. seventy-five (75) non-consecutive days;
then the party not having originally claimed Force Majeure may, no later than
thirty (30) days following the last day of the applicable period, give notice to
the claiming party that the non claiming party is electing to terminate this
Agreement on thirty (30) days' prior notice, and this Agreement then shall
terminate at the expiry of that notice period.
12.8 ALTERNATIVE SUPPLIES DURING FORCE MAJEURE PERIOD
If Seller claims Force Majeure and therefore cannot deliver gas as
originally contemplated under this Agreement, then Seller shall use its
commercially reasonable efforts to locate supplies of gas from other persons
which may be available at any delivery point on the Nova system. If Seller is
successful in locating such alternative gas supplies, which could make up the
shortfall either in whole or in part, then Seller will immediately advise Buyer
of the quantity, price, and other pertinent terms of the alternate gas supply.
If Buyer approves, then Seller shall use its reasonable efforts to obtain that
supply for resale to Buyer under this Agreement, and if so obtained Buyer shall
reimburse Seller for all incremental costs incurred by Seller in so obtaining
the alternate gas supply.
12.9 PRO RATA TREATMENT
a. If Seller declares Force Majeure, then commencing on the day of
declaration and for each and every Force Majeure day, Seller shall:
i. first curtail and cease delivering interruptible gas to all of its
interruptible markets at the Delivery Point on that day, to the
extent necessary to enable Seller to satisfy its delivery
obligation under this Agreement for that day, but only if that
interruptible gas supply could physically replace gas which would
have been purchased under this Agreement at the Delivery Point,
but for the Force Majeure;
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ii. next ensure that the amount of firm gas supply available from
Seller's Suppliers during any day of the Force Majeure period is
delivered on an equitable and pro rata share basis among Seller's
distributor customers under contract for firm deliveries at the
Delivery Point. For the purposes of this Section "pro rata share"
means a percentage share equal to 21.849% of the available
Seller's Suppliers gas supply for the day.
b. If Buyer declares Force Majeure, then commencing on the day of
declaration and for each and every Force Majeure day, Buyer shall:
i. first curtail and cease purchasing gas from all of its
interruptible suppliers at the Delivery Point on that day, to the
extent necessary to enable Buyer to satisfy its purchase
obligations under this Agreement for that day, but only if that
interruptible gas supply could be physically replaced by gas which
would have been purchased under this Agreement at the Delivery
Point, but for the Force Majeure;
ii. next ensure that the amount of firm gas purchase curtailment under
this Agreement is no greater than an equitable and pro rata share
of the total amount Buyer is unable to purchase due to the Force
Majeure event. That pro rata share shall be based on the DCQ
under this Agreement compared to the total of all daily quantity
amounts under Buyer's firm gas purchase contracts having a term
equal to or in excess of thirty (30) days.
12.10 NO EXTENSION TO TERM
No claim of Force Majeure by either Seller or Buyer shall operate
to extend the term of this Agreement.
ARTICLE 13
BILLINGS AND PAYMENTS
13.1 MONTHLY INVOICE
a. On or before the Invoice Date, for each month, Seller shall submit to
Buyer a statement for the preceding month showing the daily amounts of
gas delivered hereunder, the ANG Heating Value thereof, the Monthly Sales
Quantity, and an invoice with respect to all amounts owing in respect of
the preceding month. All amounts hereunder which are initially
calculated in Canadian dollars shall be converted to a U.S. dollar amount
for the purposes of invoicing, utilizing the Exchange Rate in effect on
the Business Day immediately prior to the date that the invoice was
prepared. Each statement shall contain information which sets out in
reasonable detail how all invoice amounts were determined.
b. If, by the Invoice Date in any month, Seller has not received any of the
actual figures required to determine the amount due to it, then it shall
be entitled to use its best estimate of the figures. Any variance between
the estimate and the actual figure shall be adjusted and accounted for as
soon as possible on a subsequent invoice.
13.2 PAYMENT DUE DATE
Buyer shall pay to Seller the amount due to Seller, by means of a
wire transfer of U.S. funds, on or before the Payment Due Date. The wire
transfer shall be made to Seller's credit at a bank or deposit taking
institution in Canada or the United States in accordance with Seller's written
instructions.
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13.3 EXAMINATION OF RECORDS
It is the intent of the parties to cooperate with one another to
verify the accuracy of any statement or invoice made under or pursuant to the
provisions of this Agreement.
13.4 REMEDIES FOR NON-PAYMENT
a. If Buyer fails to pay all of the amount of any invoice as herein provided
when such amount is due, then interest shall accrue on the unpaid part of
the invoice from the Payment Due Date until the date payment is made, at
an annual rate equal to the Prime Rate plus two percent (2%), calculated
and compounded monthly, but in no event to exceed the maximum interest
rate permitted by law, and shall be payable both before and after
judgment. All such interest shall be payable by Buyer to Seller without
demand of Seller to Buyer. The provisions of this subsection 13.4(a)
shall survive the termination of this Agreement.
b. If any failure to pay continues for a period of five (5) days after the
Payment Due Date, then Seller may, in addition to all other remedies that
it may have under the terms of this Agreement, but only upon providing at
least five (5) days' notice to Buyer, suspend any further deliveries of
gas hereunder until the overdue amount, including interest, is paid.
During the period of suspension Seller shall be relieved of all
obligations to deliver gas to Buyer under this Agreement. The suspension
of deliveries by Seller shall not in any way relieve Buyer of its
obligation to pay the Nova Demand Charges, the ANG Demand Charges, the
Supplier Demand Charges and the Kingsgate Administration Charges.
c. Notwithstanding the provisions of subsection 13.4(b), if Buyer in good
faith disputes all or any portion of the amount payable, pays to Seller
the amounts as Buyer concedes to be correct, and opens an interest
bearing escrow account and on or before the Payment Due Date and deposits
funds into the account equal to the amount which is in dispute, then
Seller shall not be entitled to suspend further delivery of gas hereunder
because of such non-payment unless and until Buyer defaults in making
payments to Seller or into the escrow account, as the case may be.
d. When the dispute is resolved either by agreement or the judgment of the
Courts, as the case may be, then the funds in the escrow account shall be
paid to the party or parties in accordance with the resolution of the
dispute. Interest at the rate specified in Subsection a. above
accumulated in the escrow account shall also be paid to the party or
parties, in the same proportions as the principal amount is to be paid to
the party or parties.
e. If Buyer does not in good faith dispute the payment of the amount in
accordance with subsection 13.4 c. above, or fails to deposit the
required funds into the escrow account, then Seller may, in addition to
any other remedies that it may have under the terms of this Agreement, at
law or in equity, but only upon providing at least five (5) days' notice
to Buyer which notice may only be given by Seller after a period of
thirty (30) days after the Payment Due Date has expired, elect to
terminate this Agreement effective the end of such notice period. This
Agreement then shall terminate at the end of that period, unless Buyer
has made payment of the overdue amount, including interest, and all other
amounts then due.
13.5 ADJUSTMENTS
a. If it is found that at any time Buyer has been overcharged by Seller in
relation to this Agreement and Buyer actually has paid the statement
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containing the overcharge, then within thirty (30) days after a final
determination of the overcharge has occurred, Seller shall refund the
amount of the overcharge. If the overcharge was the result of Seller's
error, then interest at an annual rate equal to the Prime Rate plus two
percent (2%), calculated and compounded monthly, but in no event to
exceed the maximum interest rate permitted by law, shall be paid by
Seller on the amount in question from the date the overcharge was paid to
the date that Buyer is reimbursed for the overcharge. If any such
overcharge is not a result of an error on the part of Seller, then no
interest shall be charged to Seller.
b. If it is found that at any time Buyer has been undercharged in relation
to this Agreement, then within thirty (30) days after the final
determination the undercharge has occurred, Buyer shall pay the amount
undercharged. No interest shall be payable by Buyer on the amount of any
undercharge unless Buyer fails to pay the amount of it within the thirty
(30) day period, in which event interest shall be calculated and payable
from the first day after the thirty (30) day period to the date of
payment of the undercharge by Buyer, at an annual rate equal to the Prime
Rate plus two percent (2%), calculated and compounded monthly, but in no
event to exceed the maximum interest rate permitted by law.
c. Either party discovering an overcharge or undercharge shall promptly
notify the other party. The provisions of this Section 13.5 shall
survive the termination of this Agreement.
13.6 LIMITATION ON DISPUTES
Notwithstanding anything herein contained to the contrary, neither
party shall be entitled to dispute the quantity of gas delivered, or the amount
paid or payable with respect thereto, unless any such issue is raised by notice
to the other party within two (2) years after the end of the month in question.
The provisions of this Section 13.6 shall survive the termination of this
Agreement.
ARTICLE 14
NOTICE
14.1 SERVICE OF NOTICE
All notices, communications, invoices and statements required or
permitted under this Agreement shall be in writing except as set out
specifically in this Agreement. Any notice to be given hereunder shall be
deemed to be served properly if served in any of the following modes:
a. if personally or by courier, then by delivering the notice to the
attention of the person specified below and leaving it with that person
or a director, officer, office manager or other responsible employee of
the party at that party's address for service, or any other location to
which the party has removed itself and for which it has not given formal
notice. Personally served notices shall be deemed received by the
addressee when actually so delivered, but delivery shall be during normal
business hours, on a Business Day. If a notice is not delivered during
the addressee's normal business hours, the notice shall be deemed to have
been received by such party at the commencement of the next Business Day
following the date of delivery;
b. if by telecopier, then by directing it to the addressee at that receiving
party's number. A notice so served shall be deemed received by the
addressees when actually received by it, if received within normal
business hours on a Business Day, or at the commencement of the next
ensuing Business Day following transmission, if the notice is not
received during normal business hours;
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c. if by mail, then by mailing it first class registered post, postage
prepaid, directed to the receiving party at that party's address for
service listed below. If postal service is interrupted or operating with
unusual or imminent delay, notice shall not be served by such mail during
that period. Notices served by mail shall be deemed to be received by
the addressee at noon, local time, on the fifth (5th) Business Day
following the mailing.
Notwithstanding the foregoing, payments shall not be so deemed
delivered until actually received.
14.2 ADDRESSES AND NUMBERS FOR NOTICES
The address and numbers for service of notices and communications
for each of the parties shall be as follows:
a. to Seller:
Westcoast Gas Services Inc.
3520, 150 - 6th Avenue S.W.
Calgary, Alberta
T2P 3Y7
i. GENERAL NOTICES
Attention: Director, Marketing (Pacific Northwest
Region)
Telephone: (403) 297-1838
Telecopy: (403) 297-8643
ii. NOMINATIONS/OPERATIONS
Attention: Operations Representative (Pacific Northwest
Region)
Telephone: (403) 297-0337
Telecopy: (403) 297-8643
b. to Buyer:
Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington, 98109
i. GENERAL NOTICES
Attention: Vice President, Gas Supply
Telephone: (206) 624-3900
Telecopy: (206) 624-7215
ii. NOMINATIONS/OPERATIONS
Attention: Manager, Gas Management
Telephone: (206) 624-3900
Telecopy: (206) 624-7215
14.3 RIGHT TO CHANGE ADDRESS AND NUMBERS
Any party may change its address, telephone number, telecopy
number or the person specified above by notice to the other party and any such
change subsequently shall be effective for all purposes of this Agreement.
ARTICLE 15
ASSIGNMENT
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15.1 NO ASSIGNMENT OF AGREEMENT WITHOUT CONSENT
Either party may assign its interest under this Agreement without
the consent of the other part, to an Affiliate whose performance the assignor
guarantees or to any person which may succeed, by purchase, merger,
consolidation or other transfer, to substantially all of the assignor's assets.
In the event of any such assignment or disposition, the successor shall be
entitled to the rights and shall be subject to the obligations of its
predecessor. Except as otherwise provided in this Article, neither party shall
have the right to assign this Agreement or any of its rights, benefits, duties
and obligations hereunder without the prior written consent of the other party,
which consent shall not be unreasonably withheld.
15.2 ASSIGNMENTS BY WAY OF SECURITY
The requirement in Section 15.1 to obtain prior written consent
from the non-assigning party shall not apply to an assignment made by way of
security for the assignor's present or future indebtedness or liabilities
(whether contingent, direct or indirect and whether financial or otherwise), the
issue of the bonds or debentures of a corporation or the performance of the
obligations of the assignor as guarantor under a guarantee. In the event that
the security is enforced by sale or foreclosure, Section 15.1 shall apply.
15.3 ENUREMENT
Subject to this Article 15, the terms, covenants and conditions
hereof shall be binding upon and enure to the benefit of the parties hereto and
on their respective successors and permitted assigns.
ARTICLE 16
ARBITRATION
16.1 SUBMISSIONS
Any dispute, controversy, claim, difference or question between
the parties arising out or of connected with the Agreement in respect to which
the parties have both agreed to have resolved by arbitration, except where the
Final Offer Arbitration procedure is to be used, shall be resolved by
arbitration in accordance with the provisions of this Article 16.
16.2 SELECTION OF ARBITRAL INSTITUTION
The parties may need the services of an arbitral institution from
time to time in connection with arbitration proceedings carried out in
accordance with the provisions of this Article 16. The parties agree to use the
AAA and the BCICAC for this purpose and will alternate the use of the AAA and
the BCICAC with the BCICAC chosen for the first arbitration. The choice of the
Arbitral Institution shall alternate for subsequent arbitrations carried out in
accordance with the provisions of Article 16 each time an arbitration proceeds
as far as the selection of a single arbitrator (the "ARBITRATOR") or the three
arbitrators (the "BOARD") under this Article 16.
16.3 COMMENCEMENT OF PROCEEDINGS
Either party (the "INITIATING PARTY") may commence an arbitration
proceeding by serving notice on the other party (the "RECEIVING PARTY"), which
notice shall contain: the name of one (1) arbitrator who would either function
as a single arbitrator if the Receiving Party consents, or as one of a panel of
three arbitrators if the Receiving Party does not so consent; a statement of the
matters in dispute; a request for relief; and the grounds therefor. Within
twenty-one (21) days after receipt of such notice, the Receiving Party shall
serve notice on the Initiating Party, which notice shall contain: either a
consent to the Initiating Party's arbitrator functioning as a
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single arbitrator; or the name of a second arbitrator to function as a member of
an arbitration board; a statement answering the Initiating Party's statement of
the matters in dispute and specifying other matters that may also be in dispute,
if any; a counter request for relief, if applicable; and the grounds therefor.
16.4 APPOINTMENT OF ARBITRATORS
If the Receiving Party fails either to consent to a single
arbitrator or to name a second arbitrator, then the Initiating Party's
arbitrator shall function as a single arbitrator. If both parties appoint their
own arbitrator, the two arbitrators so appointed shall name a third arbitrator
or, if they fail to do so within fourteen (14) days of the second arbitrator's
appointment, the parties shall promptly meet and shall attempt to agree upon and
to appoint such third arbitrator. If the parties are unable to agree within a
further fourteen (14) days on the choice of a third arbitrator, then upon
application by either party, the third arbitrator shall be appointed by the
applicable Arbitral Institution.
16.5 EXPERIENCE
The Arbitrator or the Board appointed hereunder shall be generally
knowledgeable in the areas of gas production, transportation, marketing and
distribution, shall be qualified by eduction or experience to decide the
particular matters in dispute, shall be a disinterested party or parties and
shall not be employees or agents of either party or of any of their Affiliates.
Any arbitrator must be Canadian or American.
16.6 LOCATION OF ARBITRATION HEARING
Unless otherwise agreed to by the parties, the place of any
arbitration hearing shall be Vancouver, British Columbia, if the BCICAC is the
applicable Arbitral Institution or Seattle, Washington, if the AAA is the
applicable Arbitral Institution. The exact location of any hearing shall be
determined by the applicable Arbitral Institution.
16.7 HEARING
The Arbitrator or the Board, as the case may be, shall promptly
hear and determine the matters in dispute after giving the parties due notice of
hearing and a reasonable opportunity to be heard.
16.8 DECISION
The Arbitrator or the Board (or a majority thereof), as the case
may be, shall render a decision within forty-five (45) days after the hearing
has commenced, subject to any reasonable delay due to unforeseen circumstances.
The decision of the Arbitrator, or the decision of the Board (or a majority
thereof), as the case may be, shall be made in writing and shall be final and
binding upon the parties as to the matters submitted to arbitration and the
parties shall abide by and comply with the decision. There shall be no appeal
from such decision and an order confirming the decision or judgment may be
entered in any Court having jurisdiction. The parties agree that the decision
of the Arbitrator or the Board (or a majority thereof), as the case may be,
shall be the sole and exclusive remedy between them regarding the issue in
dispute and that any costs or fees incidental to enforcing the decision shall,
to the maximum extent permitted by law, be charged against the party resisting
such enforcement. The parties shall execute, acknowledge and deliver all such
documents or assurances as may be necessary to implement the decision. The
written decision of the Arbitrator or the Board (or a majority thereof), as the
case may be, may be issued with or without a written opinion. Either party may
request a written opinion with regard to a decision and, if a request is made, a
written opinion shall be issued expeditiously; provided that, implementation of
and compliance with the decision shall not be delayed pending the issuance of a
written opinion.
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16.9 COSTS
Each party shall bear the expense of prosecuting its own case and
each party shall pay the compensation and expenses of its named arbitrator when
a Board is selected. The compensation and expenses of an Arbitrator or a third
arbitrator and all administration costs of the arbitration, including the fees
of the applicable Arbitral Institution, shall be paid in equal portions by the
parties.
16.10 FAILURE TO PARTICIPATE
The failure of either party to participate in any arbitration
proceeding as scheduled by the Arbitrator or the Board, as the case may be,
shall not delay the proceeding. Notwithstanding a party's failure to
participate, the Arbitrator or the Board, as the case may be, shall proceed to
consider submissions, to take evidence, and to issue a decision as though such
party were a participant in the arbitration proceeding and the decision shall be
final and binding on such non-participating party in accordance with Section
16.8.
16.11 PROVISIONAL REMEDIES
The Arbitrator or the Board ( or a majority thereof), as the case
may be, may grant such provisional remedies as it deems necessary and
appropriate in its sole discretion.
16.12 ARBITRATION PROCEDURES
Except as herein otherwise expressly provided, all arbitration
proceedings conducted pursuant to Article 16 shall be conducted pursuant to the
rules of the applicable Arbitral Institution which apply to international
commercial arbitrations and which are in effect at the commencement of the
arbitration proceedings. In the event of conflict, the provisions of this
Agreement shall prevail and govern.
16.13 CONTINUATION OF OPERATIONS
Whenever there is an arbitration proceeding under this Article,
operations under this Agreement shall continue in the same fashion as they were
conducted before the arbitration proceeding was commenced, without prejudice to
either party, pending a decision in the arbitration proceeding.
16.14 MODIFICATION OF CERTAIN AAA RULES
In addition to the express provisions of this Article, the parties
agree to further modify the AAA rules as follows:
a. The Expedited Procedures under the AAA Rules shall not apply to any
matter submitted for arbitration under this Agreement.
b. A party appointed arbitrator may be disqualified for the reasons set
forth in Section 19 of the AAA Rules as such may be amended from time to
time.
c. Notice of the date and time of the hearing will be provided to the
parties by the AAA at least forty-five (45) days in advance of the
hearing.
ARTICLE 17
FINAL OFFER ARBITRATION
17.1 SUBMISSIONS
In the event that the parties have not documented their agreement
on a redetermined Gas Commodity Price in a letter executed by both
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parties by the deadline set out in Section 7.14 b above, or the requisite
producer support referred to in Section 7.15 above is not obtained by the
following September 1st, and either party subsequently initiates Final Offer
Arbitration pursuant to Section 7.14 b, then any redetermination of the Gas
Commodity Price shall be resolved by Final Offer Arbitration proceedings
conducted in accordance with the provisions of this Article 17.
17.2 SELECTION OF ARBITRAL INSTITUTION
The parties may need the services of an arbitral institution from
time to time in connection with Final Offer Arbitration proceedings conducted in
accordance with the provisions of this Article 17. The parties agree to use the
AAA and the BCICAC for this purpose, and will alternate the use of the AAA and
the BCICAC, with the BCICAC chosen for the first Final Offer Arbitration. The
choice for the Arbitral Institution shall alternate for subsequent Final Offer
Arbitrations each time a Final Offer Arbitration proceeds as far as the
selection of the single arbitrator (the "ARBITRATOR") under this Article 17.
17.3 COMMENCEMENT OF PROCEEDING
Pursuant to the provisions of Section 7.14 b, either party (the
"INITIATING PARTY") may commence a Final Offer Arbitration proceeding by serving
notice on the other party (the "RECEIVING PARTY"), which notice shall contain
the name of one (1) arbitrator who would function as the single gas price
arbitrator. Within seven (7) days after receipt of the notice, the Receiving
Party shall serve written reply to the Initiating Party, which reply shall
contain either a consent to the Initiating Party's arbitrator functioning as the
single arbitrator, or the name of an alternate person to function as the gas
price arbitrator.
17.4 APPOINTMENT OF ARBITRATORS
If the Receiving Party fails either to consent to the Initiating
Party's single arbitrator or to name an alternate arbitrator, then the
Initiating Party's arbitrator shall function as the single arbitrator. If the
parties are unable to agree on a single arbitrator within seven (7) days of the
Receiving Party's reply, then the arbitrator shall be appointed by the
applicable Arbitral Institution.
17.5 EXPERIENCE
The Arbitrator shall be generally knowledgeable in the areas of
gas production, transportation, marketing and distribution as they relate to the
Pacific Northwest, shall be qualified by education or experience to decide the
particular matters in dispute, shall be a disinterested party and shall not be
an employee or agent of either party or of any of their Affiliates. The
arbitrator must be Canadian or American.
17.6 LOCATION OF FINAL OFFER ARBITRATION
Unless otherwise agreed to by the parties, the place of
arbitration shall be Vancouver, British Columbia, if the BCICAC is the
applicable Arbitral Institution, or Seattle, Washington, if the AAA is the
applicable Arbitral Institution.
17.7 FINAL OFFERS
Both parties shall independently submit to the Arbitrator within
seven (7) days of his appointment, a one time written price offer ("FINAL
OFFER") which will set out that party's proposed Gas Commodity Price for the
Contract Year in dispute. After the Arbitrator has received each party's Final
Offer,
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each party shall be provided with a copy of the other party's Final Offer. The
Arbitrator shall consider the two Final Offers and shall only have authority to
select the one Final Offer which the Arbitrator believes most fairly reflects
the Pricing Criteria set forth in Section 7.14 above.
17.8 NO HEARING ON FINAL OFFER ARBITRATION
a. The parties acknowledge and confirm that Final Offer Arbitration is
governed by the written submissions of the parties to the Arbitrator, and
accordingly, there shall be no hearing for the parties in front of the
Arbitrator.
b. In addition to the Final Offer written submission, each party may prepare
and submit to the Arbitrator a brief statement in support of the Final
Offer price calculation, which statement principally shall speak to the
Pricing Criteria set forth in Section 7.14 above and how, in the view of
the submitter, its Final Offer price calculation most appropriately
satisfies that criteria.
17.9 DECISION
The Arbitrator shall select a Final Offer within thirty (30) days
after the deadline date for Final Offer submissions, subject to any reasonable
delay due to unforeseen circumstances. The selection by the Arbitrator shall be
made in writing and shall be final and binding upon the parties as to the
determination of a Gas Commodity Price, and the parties shall abide by and
comply with the selection. There shall be no appeal from the selection and an
order confirming the selection or judgment may be entered in any Court having
jurisdiction. The parties agree that the Final Offer selection by the
Arbitrator shall be the sole and exclusive remedy between them regarding the
determination of the Gas Commodity Price, and that any costs or fees incidental
to enforcing the selection shall, to the maximum extent permitted by law, be
charged against the party resisting the enforcement. The parties shall execute,
acknowledge and deliver all such documents or assurances as may be necessary to
implement the selection. The written selection of the Arbitrator may be issued
with or without written elaboration. Either party may request written
elaboration with regard to a selection and, if a request is made, a written
elaboration shall be issued expeditiously, but implementation of and compliance
with the selection shall not be delayed pending the issuance of a written
elaboration.
17.10 COSTS
Each party shall bear its own Final Offer Arbitration expenses.
The compensation and expenses of the Arbitrator and all administration costs of
the Final Offer Arbitration, including any applicable fees of the applicable
Arbitral Institution, shall be paid in equal portions by the parties.
17.11 FAILURE TO PARTICIPATE
The failure of either party to participate in any Final Offer
Arbitration selection process shall not delay that process. If a party fails to
participate, the Arbitrator shall select the participating party's Final Offer,
and issue a selection confirmation as though the non-participating party were a
participant in the Final Offer Arbitration proceeding, and the decision shall be
final and binding on the non-participating party in accordance with Section
17.9.
17.12 FINAL OFFER ARBITRATION PROCEDURES
Except as otherwise expressly provided in this Article which
otherwise prevail in the event of conflict, all Final Offer Arbitration
proceedings conducted pursuant to the provisions of Article 17 shall be
conducted pursuant to the rules of the applicable Arbitral Institution which
apply to international commercial arbitrations and which are in effect at the
commencement of the arbitration proceedings.
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17.13 CONTINUATION OF OPERATIONS
Whenever there is a Final Offer Arbitration proceeding under this
Article, operations under this Agreement shall continue in the same fashion as
they were conducted before the Final Offer Arbitration proceeding was commenced,
without prejudice to either party, pending a Final Offer Arbitration price
selection.
ARTICLE 18
GENERAL
18.1 PROPER LAW
This Agreement and all matters arising directly in relation to it,
including without limitation the capacity, form, essentials and performance of
this Agreement, shall be governed by and construed in accordance with the laws
of the State of Washington. In the event that any legal action is brought under
or in relation to this Agreement, venue shall be proper in the County of King,
in the State of Washington.
18.2 ATTORNMENT
Each of the parties, by the execution and delivery of this
Agreement, irrevocably and unconditionally, with respect to any matter or thing
arising out of or pertaining to this Agreement, attorns and submits to and
accepts, for itself and in respect of its assets, the jurisdiction of the courts
of the State of Washington.
18.3 COMPLIANCE WITH LAW
This Agreement and the rights and obligations of the parties to it
are subject to all applicable present and future valid laws, regulations,
orders, directives, and rules of any legislative body or regulatory authority
having jurisdiction over the parties or the subject matter of this Agreement.
18.4 TIME
Time shall be of the essence in this Agreement.
18.5 NO AMENDMENT EXCEPT IN WRITING
No amendment or variation of the provisions of this Agreement
shall be effective or binding upon the parties unless it is set forth in writing
and has been duly executed by each of the parties by its respective proper
officers or authorized representatives in that behalf.
18.6 ENTIRE AGREEMENT
This Agreement constitutes the entire agreement between the
parties relative to the expressed matters and there are no other written or
verbal representations, warranties or covenants in respect thereto. Subject to
the provisions of Article 2 above, this Agreement supersedes all prior or
contemporaneous discussions, negotiations, representations or agreements
relating to the subject matter of this Agreement including, without limiting the
generality of the foregoing, the Kingsgate Gas Sales Agreement.
18.7 FURTHER ASSURANCES
Each of the parties shall, from time to time and at all times
hereafter, do all such further acts and execute and deliver all such further
deeds and documents as shall be reasonably required in order to fully perform
and to more effectively implement and carry out the terms of this Agreement.
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18.8 SEVERABILITY
The intention of the parties is to comply fully with all laws, and
this Agreement shall be construed consistently with all laws. In the event that
any one or more terms or provisions of this Agreement are found to be void or
unenforceable for any reason the subject terms and provisions shall be
considered, at such time, to be deleted from this Agreement and this Agreement
shall continue in full force and effect as if those terms and provisions were
never part of this Agreement.
18.9 ALTERNATE REMEDIES
Any default of a party under this Agreement shall give the non-
defaulting party the right to seek its full remedies in law or in equity against
the defaulting party notwithstanding that the non-defaulting party has alternate
remedies under this Agreement, except if a remedy for a default is stated to be
the sole remedy available to the non-defaulting party or if a party's remedies
are otherwise specifically limited hereunder. The parties hereby agree that the
indemnities which have been agreed to and delineated in this Agreement are
genuine and commercially reasonable pre-estimates as liquidated damages, and not
as penalties.
18.10 WAIVER
Either party may, in its sole discretion, waive any provision
hereof which is for the benefit or protection of that party, or may waive any
breach or default by the other party, but the waiver must be in writing. No
failure by any party to insist upon compliance with any term of this Agreement
or to enforce any right, or seek any remedy, upon any default of the other
party, shall affect or constitute a wavier of the first party's right to insist
upon strict compliance, enforce that right or seek that remedy with respect to
any prior, contemporaneous, or subsequent default. No custom or practice of the
parties at variance with any provisions of this Agreement shall affect, or
constitute a waiver of any party's right to demand strict compliance with all
provisions of this Agreement.
18.11 COUNTERPART EXECUTION
This Agreement may be executed in counterpart and when so executed
shall have the same effect as if all parties had executed the same document.
Each party executing a counterpart of this Agreement shall deliver one executed
copy of such counterpart to the other party.
18.12 CONFIDENTIALITY
The parties agree that the provisions of this Agreement and its
resulting transactions shall be kept strictly confidential, except to the
extent: required by applicable law; or either party is required to disclose
pertinent information concerning this Agreement to lenders, underwriters,
regulators, parties subject to Protective Orders issued by Buyer's regulators,
Pan-Alberta, Pan-Alberta's participating pool producers in the ordinary course
of obtaining the requisite support as described in Section 7.15 above; or the
parties mutually agree to a release of a summary of the agreement provisions.
If either party makes such a disclosure, it shall advise the party receiving the
information that it is strictly confidential.
18.13 EQUAL OPPORTUNITY
a. The provisions of this Section 18.13 are applicable only to the extent
Seller is subject to United States federal or state employment laws or
regulations. Seller will not discriminate against any Seller employee or
applicant for employment because of race, colour, religion, sex, or
national origin. Seller will take affirmative action to ensure that
applicants are employed, and that employees are treated during
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employment, without regard to their race, colour, religion, sex, or
national origin. Such action shall include, but not be limited to the
following: employment, upgrading, demotion, or transfer, recruitment or
recruitment advertising; layoff or termination; rates of pay or other
forms of compensation; and selection for training, including
apprenticeship. Seller agrees to post in conspicuous places, available
to American employees and applicants for employment, notices to be
provided by the Seller setting forth the provisions of this non-
discrimination clause.
b. Seller will, in all solicitations or advertisements for American
employees placed by or on behalf of Seller, state that all qualified
applicants will receive consideration for employment without regard to
race, colour, religion, sex, or national origin.
c. Seller will send to each labour union or representative of workers with
which he has a collective bargaining agreement or other contract or
understanding, a notice to be provided by the agency contracting officer,
advising the labour union or workers' representative of the Seller's
commitments under section 202 of Executive Order 11246 of September 24,
1965, and shall post copies of the notice in conspicuous places available
to American employees and applicants for employment.
d. Seller will comply with all provisions of Executive Order 11246 of
September 24, 1965, and of the rules, regulations, and relevant orders of
the Secretary of Labour as applicable to its American employees.
e. Seller will furnish all information and reports required by Executive
Order 11246 of September 24, 1965, and by the rules, regulations, and
orders of the Secretary of Labour, or pursuant thereto, and will permit
access to his books, records, and accounts by Seller and the Secretary of
Labour for purposes of investigation to ascertain compliance with such
rules, regulations, and orders.
f. In the event of the Seller's non-compliance with the non-discrimination
clauses of this Section or with any of such rules, regulations, or
orders, this Agreement may be cancelled, terminated or suspended in whole
or in part and Seller may be declared ineligible for further Government
contracts in accordance with procedures authorized in Executive Order
11246 of September 24, 1965, and such other sanctions may be imposed and
remedies invoked as provided in Executive Order 11246 of September 24,
1965, or by rule, regulation, or order of the Secretary of Labour, or as
otherwise provided by law.
g. Seller will include the provisions of Subsections a. through f. in every
American subcontract or purchase order unless exempted by rules,
regulations, or orders of the Secretary of Labour issued pursuant to
section 204 of Executive Order 11246 of September 24, 1965, so that such
provisions will be binding upon each subcontractor or vendor. Seller
will take such action with respect to any American subcontract or
purchase order as may be directed by the Secretary of Labour as a means
of enforcing such provisions including sanctions for non-compliance:
provided, however, that in the event Seller becomes involved in, or is
threatened with, litigation with an American subcontractor or vendor as a
result of such direction, Seller may request the United States to enter
into such litigation to protect the interests of the United States.
IN WITNESS WHEREOF the parties hereto have duly executed and
delivered this Agreement under the signatures of their respective proper
officers duly authorized in that behalf as of the day, month and year first
above written.
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WESTCOAST GAS SERVICES INC.
Per: ________________________________
Title: ______________________________
Per: ________________________________
Title: ______________________________
CASCADE NATURAL GAS CORPORATION
Per: ________________________________
Title: ______________________________
Per: ________________________________
Title: ______________________________
THIS IS PAGE 42 TO THE AMENDED AND RESTATED GAS SALES AGREEMENT BETWEEN
WESTCOAST GAS SERVICES INC. ("SELLER") AND CASCADE NATURAL GAS CORPORATION
("BUYER")
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<PAGE>
EXHIBIT 10-23
FIRM TRANSPORTATION SERVICE AGREEMENT
THIS AGREEMENT is made and entered into this 4th day of November 1994, by
and between PACIFIC GAS TRANSMISSION COMPANY, a California
corporation(hereinafter referred to as "PGT") and
CASCADE NATURAL GAS CORPORATION, a U.S. corporation existing under the laws
of the State of Washington, (hereinafter referred to as "Shipper").
WHEREAS, PGT owns and operates a natural gas pipeline transmission system
which extends from a point of interconnection with the pipeline facilities of
Alberta Natural Gas Company Ltd. (ANG) at the International Boundary near
Kingsgate, British Columbia, through the states of Idaho, Washington and Oregon
to a point of interconnection with Pacific Gas and Electric Company at the
Oregon-California border near Malin, Oregon; and
WHEREAS, Shipper desires PGT, on a firm basis, to transport certain
quantities of natural gas from Kingsgate, British Columbia and/or from
Stanfield, Oregon to various delivery points as specified in Exhibit "A" of this
Agreement; and
WHEREAS, this Agreement will supersede the January 29, 1993 Firm
Transportation Service Agreement between PGT and Shipper for firm transportation
service under PGT's Rate Schedule T-3; and
WHEREAS, PGT is willing to transport certain quantities of natural gas for
Shipper on a firm basis,
NOW, THEREFORE, the parties agree as follows:
I. GOVERNMENTAL AUTHORITY
1.1 This Firm Transportation Agreement ("Agreement") is made pursuant to
the regulations of the Federal Energy Regulatory Commission (FERC) contained in
18 CFR Part 284, as amended from time to time.
<PAGE>
I. GOVERNMENTAL AUTHORITY
(continued)
1.2 This Agreement is subject to all valid legislation with respect to the
subject matters hereof, either state or federal, and to all valid present and
future decisions, orders, rules, regulations and ordinances of all duly
constituted governmental authorities having jurisdiction.
1.3 Shipper shall reimburse PGT for any and all filing fees incurred by
PGT in seeking governmental authorization for the initiation, extension, or
termination of service under this Agreement and Rate Schedule FTS-1. Shipper
shall reimburse PGT for such fees at PGT's designated office within ten (10)
days of receipt of notice from PGT for any and all penalty fees or fines
assessed PGT caused by the negligence of Shipper in not obtaining all proper
Canadian and domestic import/export licenses, surety bonds or any other
documents and approvals related to the Canadian exportation and subsequent
domestic importation of natural gas transported by PGT hereunder.
II. QUANTITY OF GAS AND PRIORITY OF SERVICE
2.1 Subject to the terms and provision of this Agreement and PGT's
Transportation General Terms and Conditions contained in PGT's FERC Gas Tariff
First Revised Volume No. 1-A applicable to Rate Schedule FTS-1, daily receipts
of gas by PGT from Shipper at the point(s) of receipt shall be equal to daily
deliveries of gas by PGT to Shipper at the point(s) of delivery; provided,
however, Shipper shall deliver to PGT an additional quantity of natural gas at
the point(s) of receipt as compressor station fuel, line loss and unaccounted
for gas as specified in the Statement of Rates and Charges of PGT's FERC Gas
Tariff First Revised Volume No. 1-A. Any limitations of the quantities to be
received from each point of receipt and/or delivered to each point of delivery
shall be as specified on the Exhibit A attached hereto.
2.2 The maximum quantities of gas to be delivered by PGT for Shipper's
account at the point(s) of delivery are set forth in Exhibit A.
2.3 In providing service to its existing or new customers, PGT will use
the priorities of service specified in Paragraph 18 of PGT's Transportation
General Terms and Conditions on file with the FERC.
2.4 Prior to initiation of service, Shipper shall provide PGT with any
information required by the FERC, as well as all information identified in PGT's
Transportation General Terms and Conditions applicable to Rate Schedule FTS-l.
<PAGE>
III. TERM OF AGREEMENT
3.1 This Agreement shall become effective on November l, 1995 and shall
continue in full force and effect until November 1, 2015. Thereafter, this
Agreement shall continue in effect from year to year unless Shipper gives twelve
(12) months prior written notice of its desire to terminate this Agreement.
IV. POINTS OF RECEIPT AND DELIVERY
4.1 The primary point of receipt of gas deliveries to PGT is as designated
in Exhibit A, attached hereto.
4.2 The primary point of delivery of gas to Shipper is as designated in
Exhibit A, attached hereto.
4.3 Shipper shall deliver or cause to be delivered to PGT the gas to be
transported hereunder at pressures sufficient to deliver such gas into PGT's
system at the point(s) of receipt. PGT shall deliver the gas to be transported
hereunder to or for the account of Shipper at the pressures existing in PGT's
system at the point(s) of delivery.
4.4 Pursuant to Paragraph 29 of PGT'S Transportation General Terms and
Conditions, Shipper may designate other receipt and/or delivery points as
secondary receipt or delivery points.
V. OPERATING PROCEDURE
5.1 Shipper shall conform to the operating procedures set forth in PGT's
Transportation General Terms and Conditions.
5.2 Nothing in Section 5.1 shall compel PGT to transport gas pursuant to
shipper's request on any given day. PGT shall have the right to interrupt or
curtail the transport of gas for the account of Shipper pursuant to PGT's
Transportation General Terms and Conditions applicable to Rate Schedule FTS-1.
<PAGE>
VI. RATE(S), RATE SCHEDULES, AND
GENERAL TERMS AND CONDITIONS OF SERVICE
6.1 Shipper shall pay PGT each month for services rendered pursuant to this
Agreement in accordance with PGT's Rate Schedule FTS-1, or superseding rate
schedule(s), on file with and subject to the jurisdiction of FERC.
6.2 Shipper shall compensate PGT each month for compressor station fuel, line
loss and other unaccounted for gas associated with this transportation service
provided herein in accordance with PGT's Rate Schedule FTS-1, or superseding
rate schedule's), on file with and subject to the jurisdiction of the FERC.
6.3 This Agreement in all respects shall be and remains subject to the
applicable provisions of Rate Schedule FTS-1, or superseding rate schedule(s)
and of the applicable Transportation General Terms and Conditions of PGT's FERC
Gas Tariff First Revised Volume No. 1-A on file with the FERC, all of which are
by this reference made a part hereof.
6.4 PGT shall have the unilateral right from time to time to propose and file
with FERC such changes in the rates and charges applicable to transportation
services pursuant to this Agreement, the rate schedule(s) under which this
service is hereunder provided, or any provisions of PGT'S Transportation General
Terms and Conditions applicable to such services. Shipper shall have the right
to protest any such changes proposed by PGT and to exercise any other rights
that Shipper may have with respect thereto.
VII. MISCELLANEOUS
7.1 This Agreement shall be interpreted according to the laws of the State of
California.
7.2 Shipper agrees to indemnify and hold PGT harmless for refusal to transport
gas hereunder in the event any upstream or downstream transporter fails to
receive or deliver gas as contemplated by this Agreement.
<PAGE>
VII. MISCELLANEOUS
(continued)
7.3 Unless herein provided to the contrary, any notice called for in this
Agreement shall be in writing and shall be considered as having been given if
delivered by registered mail or facsimile with all postage or charges prepaid,
to either PGT or Shipper at the place designated below. Routine communications,
including monthly statements and payment, shall be considered as duly delivered
when received by ordinary mail. Unless changed, the addresses of the parties are
as follows:
"PGT"
PACIFIC GAS TRANSMISSION COMPANY 160 Spear Street Room 1900 San Francisco,
California 94105-1570 Attention: President & CEO
"Shipper"
CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue North Seattle, WA 98109
Attention: Director, Gas Supply
7.4 A waiver by either party of any one or more defaults by the other
hereunder shall not operate as a waiver of any future default or defaults,
whether of a like or of a different character.
7.5 This Agreement may only be amended by an instrument in writing executed
by both parties hereto.
7.6 Nothing in this Agreement shall be deemed to create any rights or
obligations between the parties hereto after the expiration of the term set
forth herein, except that termination of this Agreement shall not relieve either
party of the obligation to correct any quantity imbalances or Shipper of the
obligation to pay any amounts due hereunder to PGT.
7.7 Exhibit(s) A and C attached hereto are by reference and made a part
hereof for all purposes.
<PAGE>
IN WITNESS WHEREOF the parties hereto have caused this Agreement to be
executed as of the day and year first above written.
PACIFIC GAS TRANSMISSION COMPANY
Name: Stephen P. Reynolds
Title: President & CEO
Date:
CASCADE NATURAL GAS CORPORATION
Name: King Oberg
Title: Vice President, Gas Supply
Date: November 4, 1994
<PAGE>
EXHIBIT A
To the
FIRM TRANSPORTATION SERVICE AGREEMENT
Dated _
Between
PACIFIC GAS TRANSMISSION COMPANY
And
CASCADE NATURAL GAS CORPORATION
Primary
Receipt
Point
Kingsgate,
British Columbia
Primary
Delivery
Point
Malin, Oregon
(1) Winter shall be the months of November through April.
(2) Summer shall be the months of May through October.
Winter Summer
3,600 0
Maximum Daily Quantity (MDQ) (Delivered) MMBtu/d
Firm service shall be provided under PGTs Rate Schedule FTS-l or superseding
rate schedule(s) and PGTs FERC Gas Tariff, First Revised Volume No. l-A.
<PAGE>
TRANSPORTATION AGREEMENT
(Applicable to Rate Schedule TF-1)
THIS AGREEMENT is made and entered into this 1st day of August, 1994, by
and between NORTHWEST PIPELINE CORPORATION, hereinafter referred to as
"Transporter", and CASCADE NATURAL GAS CORPORATION, hereinafter referred to as
"Shipper".
RECITALS:
A. Shipper has acquired or intends to acquire firm capacity as a Replacement
Shipper from a Releasing Shipper holding Firm Transportation capacity on
Transporter's transmission system which it desires to use for transportation
pursuant to Part 284 of the Federal Energy Regulatory Commission's ("FERC")
regulations and the Transporter's Capacity Release provisions of its FERC Gas
Tariff.
B. Shipper and Transporter desire to enter into a Transportation Agreement for
the acquired firm transportation capacity pursuant to the terms as described on
each Exhibit "T" which now or hereafter amends this Agreement. Any Exhibit "T"
is hereby incorporated herein.
AGREEMENT:
NOW, THEREFORE, in consideration of the premises and mutual covenants set
forth herein, the parties agree as follows:
ARTICLE I - GAS DELIVERIES AND REDELIVERIES
1.1 Subject to the terms, conditions and limitations hereof, Transporter
agrees to receive from Shipper at the Receipt Point(s) specified in Exhibit(s)
"A" (and/or "T") herein, transport and deliver to Shipper at the Delivery
Point(s) specified in Exhibit(s) "B" (and/or "T") herein, the following
quantities of natural gas, known as Transportation Contract Demand:
Up to the Maximum Daily Quantity ("MDQ") set forth for such receipt points
and up to the Maximum Daily Delivery Obligation ("MDDO") set forth for such
delivery points on any effective Exhibit "T" of this Agreement which reflects
capacity acquired by Shipper; provided, however, that such obligation is reduced
by the quantities on any effective Exhibit "T" hereto which reflects any
subsequent release of such capacity by Shipper. These MDQ and MDDO limitations
apply only to primary point volumes and not to alternate point volumes.
1.2 Fuel gas shall be provided in-kind as specified in Rate Schedule TF-1
and in the General Terms and Conditions of Transporter's FERC Gas Tariff.
1.3 Such transportation shall be on a firm basis.
<PAGE>
ARTICLE II - TRANSPORTATION RATES AND CHARGES
2.1 (a) Shipper agrees to pay Transporter for all natural gas
transportation service rendered under the terms of this Agreement in
accordance with the terms and conditions of its successful bid for the
capacity as described on any effective Exhibit "T" of this Agreement.
(b) (Reserved for rate adjustments made pursuant to Section 3.4 or
3.5 of Rate Schedule TF-1.)
2.2 This Agreement shall be subject to the provisions of such Rate
Schedule and the General Terms and Conditions applicable thereto (and as they
may be amended by Article VIII of this Agreement) and effective from time to
time, which by this reference are incorporated herein and made a part hereof.
ARTICLE III - GOVERNMENTAL REQUIREMENTS
3.1 Shipper shall reimburse Transporter for any and all filing fees to be
incurred by Transporter in seeking governmental authorization for the
initiation, extension or termination of service under this Agreement.
3.2 The transportation service contemplated herein shall be provided by
Transporter pursuant to Section 284.223 of the FERC's regulations.
3.3 Upon termination, this Agreement shall cease to have any force or
effect, save as to any unsatisfied obligations or liabilities of either party
arising hereunder prior to the date of such termination, or arising thereafter
as a result of such termination. Provided, however that this provision shall
not supersede any abandonment authorization which may be required.
3.4 (Section 3.4 shall be applicable only for the transportation of
imported natural gas.) Shipper hereby acknowledges and agrees that either it or
its buyer or seller is the "importer of record" and it will comply with all
requirements for reporting and submitting payment of duties, fees, and taxes to
the United States or agencies thereof to be made on imported natural gas and for
making the declaration of entry pursuant to 19 CFR Section 141.19. Shipper
agrees to indemnify and hold Transporter harmless from any and all claims of
damage or violation of any applicable laws, ordinances and statutes which
pertain to the importation of the gas transported hereunder and which require
reporting and/or filing of fees in connection with said import.
ARTICLE IV - TERM
4.1 This Agreement becomes effective on the date first referenced above,
and shall remain in full force and effect, subject to the terms described on
each Exhibit "T" which now or hereafter may amend this Agreement, until
terminated by both parties.
2
<PAGE>
ARTICLE V - WARRANTY OF ELIGIBILITY FOR TRANSPORTATION
5.1 Any shipper under this Rate Schedule warrants for itself, its
successors and assigns, that all gas delivered to Transporter for transportation
hereunder shall be eligible for transportation in interstate commerce under
applicable rules, regulations or orders of the FERC. Shipper will indemnify
Transporter and save it harmless from all suits, actions, damages, costs,
losses, expenses (including reasonable attorney fees) and regulatory
proceedings, arising from breach of this warranty.
ARTICLE VI - NOTICES
6.1 Unless herein provided to the contrary, any notice called for in this
Agreement shall be in writing and shall be considered as having been given if
delivered personally, or by mail or telegraph with all postage and charges
prepaid to either Shipper or Transporter at the place designated. Routine
communications shall be considered as duly delivered when mailed by ordinary
mail. Normal operating instructions can be made by telephone. Unless changed,
the addresses of the parties are as follows:
NORTHWEST PIPELINE CORPORATION
P. O. Box 58900
Salt Lake City, Utah 84158-0900
Statements: Attention: Transmission Accounting
Payments: Attention: Treasury Services
Contractual Notices: Attention: Transportation and
Contract Administration
Other Notices: Attention: Nominations
CASCADE NATURAL GAS CORPORATION
Attn: King Oberg, Vice President
222 Fairview Avenue North (91809)
P. O. Box 24464
Seattle, Washington 98124
ARTICLE VII - OTHER OPERATING PROVISIONS
(This Article to be utilized when necessary to specify other operating
provisions required for individual transportation)
ARTICLE VIII - ADJUSTMENTS TO GENERAL TERMS AND CONDITIONS
(to be utilized when necessary for individual transportation)
8.1 Certain of the General Terms and Conditions are to be adjusted for the
purpose of this Agreement, as specified below:
3
<PAGE>
ARTICLE XI - CANCELLATION OF PRIOR AGREEMENT(S)
(to be utilized when necessary)
9.1 When this Agreement takes effect, it supersedes, cancels and
terminates the following agreement(s):
ARTICLE X - SUCCESSORS AND ASSIGNS
10.1 This Agreement shall be binding upon and inure to the benefit of the
parties hereto and their respective successors and assigns. No assignment or
transfer by either party hereunder shall be made without written approval of the
other party. Such approval shall not be unreasonably withheld. As between the
parties hereto, such assignment shall become effective on the first day of the
month following written notice that such assignment has been effectuated.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of
the day and year first above set forth.
CASCADE NATURAL GAS CORPORATION NORTHWEST PIPELINE CORPORATION
(Shipper) (Transporter)
By:___________________________ By:_____________________________
Title:________________________ Joe H. Fields
Attorney-In-Fact
Attest:_______________________
4
<PAGE>
TF-1/T00426
Page 1 of 1
EXHIBIT T
to the
FIRM TRANSPORTATION AGREEMENT
Dated 07/29/1994
between
NORTHWEST PIPELINE CORPORATION
and
CASCADE NATURAL GAS CORPORATION
Releasing Shipper: IGI Resources, Inc. - F04
Begin: 08/01/1994
End: 10/31/2009
Max Daily *Awd *Percent
Receipt Delivery Quantity Bid of Awd
Point Point (MMBTu) Rate Bid Rate
-------- ------------------------- --------- ------ --------
Sumas Kelso/Beaver Pipeline PGE 21000 787.84 cents 100.00%
* Percentage of the current effective reservation charges under the rate
schedule TF-1.
IN THE EVENT OF A BASE TARIFF MAXIMUM AND/OR MINIMUM RATE CHANGE, THE
REPLACEMENT SHIPPER WILL BE OBLIGATED TO PAY THE LESSOR OF THE AWARDED BID RATE
AND THE NEW MAXIMUM BASE TARIFF RATE, OR THE GREATER OF THE AWARDED BID RATE AND
THE NEW MINIMUM BASE TARIFF RATE, AS APPLICABLE, FOR THE REMAINING TERM OF THE
RELEASE.
<PAGE>
RELEASE AGMT # T00426
Page 1 of 1
EXHIBIT T
to the
FIRM TRANSPORTATION AGREEMENT
Dated 07/29/1994
between
NORTHWEST PIPELINE CORPORATION
and
CASCADE NATURAL GAS CORPORATION
Replacement Shipper: IGI Resources, Inc. - T00478
Begin: 08/01/1994
End: 10/31/1994
Max Daily *Awd *Percent
Receipt Delivery Quantity Bid of Award
Point Point (MMBTu) Rate Bid Rate
-------------------- ------------------------- --------- ------- --------
Sumas Kelso/Beaver Pipeline PGE -21000 787.84 cents 100.00%
* Percentage of the current effective reservation charges under the
rate schedule TF-1.
IN THE EVENT OF A BASE TARIFF MAXIMUM AND/OR MINIMUM RATE CHANGE, THE
REPLACEMENT SHIPPER WILL BE OBLIGATED TO PAY THE LESSOR OF THE AWARDED
BID RATE AND THE NEW MAXIMUM BASE TARIFF RATE, OR THE GREATER OF THE
AWARDED BID RATE AND THE NEW MINIMUM BASE TARIFF RATE, AS APPLICABLE,
FOR THE REMAINING TERM OF THE RELEASE.
<PAGE>
PREARRANGED CAPACITY RELEASE OF
FIRM NATURAL GAS TRANSPORTATION AGREEMENTS
This Capacity Release of Firm Natural Gas Transportation Agreements
("Agreement") is made as of this 30th day of November, 1993 by and among Cascade
Natural Gas Corporation, a Washington corporation with its registered office in
Seattle, Washington ("Cascade") and Tenaska Gas Co. ("Gas Co."), a Nebraska
corporation, and Tenaska Washington Partners, L.P. ("Partnership"), a Washington
limited partnership (Gas Co. and Partnership collectively referred to as
"Tenaska").
WITNESSETH:
WHEREAS, pursuant to certain Natural Gas Transportation Agreements between
Northwest Pipeline Corporation ("Northwest") and Cascade, dated the 27th day of
August, 1992 ("Northwest Transportation Agreements"), copies of which are
attached hereto as Attachment A and Attachment B, Northwest provides firm
transportation of natural gas to Cascade; and
WHEREAS, Cascade, Gas Co. and Partnership have entered into a Natural Gas
Purchase and Sale Agreement dated August 1, 1992 (the "Buy/Sell Agreement')
which contains provisions for Cascade to utilize the Northwest Transportation
Agreements to transport certain gas purchased by Cascade from Tenaska to
delivery points under the Northwest Transportation Agreements where such gas
would be resold to Tenaska; and
WHEREAS, Cascade has "grandfathered" the Buy/Sell Agreements pursuant to the
Northwest tariff in order to comply with the Federal Energy Regulatory
Commission ("F.E.R.C.") Order 636; and
WHEREAS, Partnership is constructing a cogeneration facility in the Ferndale,
Washington area (the "Facility"), and Tenaska could utilize the Northwest
Transportation Agreements to provide transportation service to the Facility
other than through the use of the Buy/Sell Agreement; and
<PAGE>
(2)
WHEREAS, Cascade wishes to permanently release, and Tenaska wishes to accept,
all of the rights and obligations under the Northwest Transportation Agreements
pursuant to the terms and conditions of this Agreement;
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, the receipt of which is hereby acknowledged, and intending to
be legally bound and to bind their successors and assigns, Gas Co., Partnership
and Cascade (the "Parties" hereto; each is a "Party") agree as follows:
1. Cascade hereby agrees to hold and maintain the Northwest Transportation
Agreements in accordance with the terms and conditions set out herein and
to permanently release unto Tenaska, and its permitted successors and
assignees, all of Cascade's right, title and interest in, to and under the
Northwest Transportation Agreements, including the right to renew or extend
the term of the Northwest Transportation Agreements, effective as of the
Capacity Release Date, such assignment and transfer being hereafter
referred to as the "Capacity Release".
2. (i) This Agreement shall be in full force and effect and binding upon
Cascade and Tenaska as of the date hereinabove stated.
(ii) Subject to subparagraph 2(v), the effective date (the "Capacity
Release Date") of Cascade's release and of Tenaska's acceptance and
assumption pursuant to Paragraph 3 of this Agreement shall be April
1, 1994.
(iii) Thirty (30) days prior to the minimum notice period required by
Northwest to allow for a capacity release on the Capacity Release
Date, Cascade shall deliver a copy of this Agreement to Northwest
and shall authorize Northwest to post any necessary information on
Northwest's Electronic Bulletin Board in accordance
<PAGE>
(3)
with Northwest's F.E.R.C. approved tariff to give effect to the
Capacity Release in the form of a capacity release to a Prearranged
Replacement Shipper (as defined in the Northwest tariff).
(iv) Prior to the posting on Northwest's Electronic Bulletin Board of
this Agreement, Tenaska shall fulfill all requirements of Tenaska in
its role as a Prearranged Replacement Shipper under the capacity
release provisions of the Northwest tariff, including the execution
of a new service agreement with Northwest to permanently replace the
Northwest Transportation Agreements ("Capacity Release Service
Agreement(s)") and its demonstration of creditworthiness to
Northwest in accordance with the Northwest tariff.
(v) If, at ten days prior to the Capacity Release Date:
(a) the Parties have not fulfilled their obligations under
Paragraph 2(iii) and 2(iv) of this Agreement such that the
Capacity Release shall be capable of being given effect
without the necessity of waiting for competing bids for the
Capacity Release to be submitted, or
(b) the Parties, together with Partnership's lenders for the
Facility, have not executed amendments to the Consent and
Agreement dated November 25, 1992 dealing with the Buy/Sell
Agreements in order to provide for the termination of the
Buy/Sell Agreement and for the inclusion of this Agreement
within the provisions of the Consent and Agreement,
then the Parties shall cooperate, in good faith, to set a new
Capacity Release Date, which date shall be the first of a month that
would allow for the Parties to comply with subparagraphs
2(iii) - (v) of this Agreement.
<PAGE>
(4)
(vi) The Capacity Releases shall be given effect pursuant to the
Northwest rules and regulations approved by the F.E.R.C. pursuant to
F.E.R.C. Order No. 636, as applicable to prearranged agreements for
capacity release, and the capacity releases shall remain subject to
all applicable F.E.R.C. rules and regulations and, to the extent
necessary, approval by Northwest. The Capacity Releases shall be
done on the basis of the full tariff rate applicable to the
Northwest Transportation Agreements subject to the capacity release.
The Capacity Releases shall be done for the full term of the
Northwest Transportation Agreements subject to the release,
including the right to renew or extend the term of the Northwest
Transportation Agreements, and shall be a "Permanent Capacity
Release" (as defined in the Northwest tariff) without any provisions
for the reversion of the Firm Transportation Agreements to Cascade
at the end of the term of the Northwest Firm Transportation
Agreements subject to the Capacity Release.
(vii) The Parties, giving due consideration to the Partnership Facility
financing and the regulatory procedures necessary for the Capacity
Release of the Northwest Transportation Agreements, hereto agree to
execute and deliver such other documents and certificates as are
reasonably necessary to carry out the purposes of this Agreement,
including but not limited to, in the case of Tenaska, the execution
and delivery of new Capacity Release Service Agreement(s) with
Northwest confirming that Tenaska has met the credit requirements of
Northwest for the purposes of the Capacity Release and Tenaska is
capable of being accepted as a contracting party in the Northwest
Capacity Release Service Agreement(s) in place and instead of
Cascade from and after the Capacity Release Date. The Parties agree
to endeavour in good faith and with due diligence to comply with the
requirements of Northwest to effectuate the capacity release
described herein and the substitution of Tenaska to Cascade's
position in the Northwest Transportation Agreements or their
replacement Northwest Service Agreements.
<PAGE>
(5)
(viii) Upon the final, effective completion of the Capacity Release
described in this Agreement, the Buy/Sell Agreement between Cascade,
Gas Co. and Partnership shall be terminated and of no further force
or effect.
3. Subject to Paragraph 2, Tenaska accepts the Capacity Release of the
Northwest Transportation Agreements and will assume all of Cascade's
rights, obligations, duties and liabilities under the Northwest
Transportation Agreements from and after the Capacity Release Date
including, but not limited to, Cascade's obligation to compensate
Transporter (as specified in the Northwest Transportation Agreements), and
all other rights, duties, liabilities and additional obligations incurred
pursuant to the provisions of the Northwest Transportation Agreements from
and after the Capacity Release Date. The Capacity Release is a release of
all of the right, title and interest of Cascade in, to and under the
Northwest Transportation Agreements and an assumption by Tenaska of all the
rights, obligations, duties and liabilities of Cascade under the Northwest
Transportation Agreements effective as of the Capacity Release Date.
4. Liability for all obligations accruing under the Northwest Transportation
Agreements prior to the Capacity Release Date shall be determined in
accordance with the provisions of the Buy/Sell Agreement or such Capacity
Releases as may be in effect as of the date of execution of this Agreement.
Tenaska hereby indemnifies Cascade against liability for all obligations
accruing under the Northwest Transportation Agreements on and after the
Capacity Release Date.
5. Cascade represents and warrants to Tenaska that the copies of the Northwest
Transportation Agreements appended hereto as Attachment A and Attachment B
are true and correct copies thereof as in effect on the date hereof and
have not been amended, modified or waived and are not subject to any prior
capacity release by Cascade that is
<PAGE>
(6)
operative on or after the Capacity Release Date and that, to the best of
Cascade's knowledge, no event has occurred as of the date hereof which,
with or without the passage of time or the giving of notice, or both, would
constitute a default on the part of Cascade thereunder.
6. From the date of execution of this Agreement until the Capacity Release
Date, Cascade agrees to hereafter operate and manage the Northwest
Transportation Agreements and activities associated therewith in accordance
with, with due regard to, and so as not to impair, Tenaska's rights under
this Agreement. Cascade will not amend, exercise elections or options or
otherwise alter the Northwest Transportation Agreements in any manner which
would affect either Party's rights or obligations under this Agreement
without Tenaska's prior written consent, which consent shall not be
unreasonably withheld. Cascade covenants and agrees not to hereafter
release all or any part of the Northwest Transportation Agreements to any
third party if such release were to impede Cascade's obligations or
Tenaska's rights under this Agreement. At the request of Tenaska, and at
Tenaska's expense, Cascade shall endeavour to secure from Northwest, any
amendments, elections, options or other alterations to the Northwest
Transportation Agreements as are reasonably requested by Tenaska from time
to time and the realization of which would not be detrimental to Cascade's
commercial interests.
7. Any notice under this Agreement shall be in writing and shall be deemed
given on the earlier of (i) the date received by the addressee when
delivered by hand, or (ii) the day following the date sent by
telecommunications means to the numbers set forth below, or (iii) five (5)
days after mailing by prepaid registered United States mail, directed to
the post office address of the parties as follows (provided that, at any
time when there is a strike affecting delivery of either United States
mail, all such deliveries shall be made by hand or by telecommunications):
<PAGE>
(7)
If to Cascade: Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington, U.S.A. 98109
Attention: Vice President, Gas Supply
Telecopy: 206/624-3900
Telephone: 206/624-7215
If to Tenaska: Tenaska Washington Partners, L.P.
407 North 117 Street
Omaha, Nebraska, U.S.A. 68154
Attention: President, Tenaska Washington, I
Telecopy: 402/691-9526
Telephone: 402/691-9500
Tenaska Gas Co.
407 North 117 Street
Omaha, Nebraska, U.S.A. 68154
Attention: President
Telecopy: 402/691-9538
Telephone: 402/691-9500
Any Party may, by like written notice, designate a new address to which
such shall be directed.
8. This Agreement can be waived, modified, amended, terminated or discharged
only explicitly in a writing signed by each of the Parties hereto. A
waiver shall be effective only in a specific instance and for the specific
purpose given. Mere delay or failure to act by a Party hereto shall not
preclude the exercise or enforcement of any of the rights or remedies
hereunder.
9. In the event that any part of this Agreement is determined by any court of
competent jurisdiction to be unenforceable, the balance of this Agreement
shall remain in full force and effect.
<PAGE>
(8)
10. The terms and provisions of this Agreement shall be binding upon and inure
to the benefit of the successors, assigns and legal representatives of the
Parties hereto. Prior to the Capacity Release Date, neither Party may
assign this Agreement or any of its rights or obligations hereunder,
without the prior written consent of the other Party, such consent not to
be unreasonably withheld. Notwithstanding the preceding, Tenaska may
assign, transfer and pledge all or any part of its rights, interests,
claims and benefits herein to any third party for the purposes of providing
security for existing or intended financing of the Facility, and Cascade
hereby consents to the creation of any lien or charge in connection
therewith. In addition, subject to establishing acceptable credit
worthiness to Northwest and the Parties, Cascade and Tenaska shall have the
right to assign this Agreement to a business entity that is affiliated with
Cascade or Tenaska (as the case may be) where such assignment is necessary
for the purpose of enabling Cascade or Tenaska to gain the maximum
commercial advantage available to it in meeting its obligations under this
Agreement.
11. Gas Co. and Partnership shall be jointly and severally liable for the
obligations of Tenaska under this Agreement however, each of Gas Co. and
Partnership shall have the right, upon sixty (60) days written notice, to
terminate this Agreement to Gas Co. only. Following the effective date of
any such termination of this Agreement as to Gas Co., (i) Gas Co. shall
have no further rights, obligations or liabilities under this Agreement,
except with respect to liabilities accruing prior to the effective date of
such termination, and (ii) this Agreement will continue in full force and
effect, without further modification or amendment, as between Cascade and
Partnership.
12. This Agreement shall be construed and enforced in accordance with, and the
rights of the Parties shall be governed by, the laws of the State of
Washington.
<PAGE>
(9)
IN WITNESS WHEREOF, Cascade, Gas Co. and Partnership have caused this Agreement
to be signed in their names by their duly authorized representatives and
delivered as their act and deed, intending to be legally bound by its terms and
provisions.
CASCADE NATURAL GAS CORPORATION Attest:
By: _________________________________ _________________________________
TENASKA GAS CO. Attest:
By: _________________________________ _________________________________
Title: Title:
TENASKA WASHINGTON PARTNERS, L.P.
By: Tenaska Washington I, L.P.,
Managing General Partner
By: Tenaska Washington, Inc.
Managing General Partner Attest:
By: _________________________________ _______________________________
Title: Title:
<PAGE>
AGREEMENT FOR
PEAK GAS SUPPLY SERVICE
("PGSS")
This Agreement ("Agreement") dated as of August 1, 1992, sets forth the
understanding of Cascade Natural Gas Corporation ("Cascade"), Tenaska Gas Co.
("Tenaska") and Tenaska Washington Partners, L.P. ("Partnership"); (Tenaska and
Partnership are, subject to the provisions of Section 28 hereof, collectively
referred to as "Seller") for Peak Gas Supply Service to Cascade for the natural
gas ("Gas") to be sold by Seller. Together Cascade, Tenaska and Partnership are
sometimes referred to as the "Parties" and individually as a "Party."
1. DEFINITIONS.
Capitalized terms used herein have the respective meanings, for all
purposes in this Agreement, as defined below or assigned thereto in the
Sections of this Agreement listed below:
"AFFILIATE" - Shall mean any Person which, directly or indirectly through
one or more intermediaries, controls or is controlled by or is under common
control with any Person including, but not limited to: a parent of a
partner; a corporation more than 50% of the voting stock of which is owned
directly or indirectly by a partner or parent of a partner of a Corporation
more than 50% of the voting stock of which is owned directly or indirectly
by a corporation more than 50% of the voting stock of which corporation is
owned directly or indirectly by a partner or by a parent of a partner.
<PAGE>
Agreement for Peak Gas Supply Service Page 2
"BTU" - Shall mean the amount of heat required to raise the temperature of
one pound of water from fifty-nine degrees Fahrenheit (59 DEG.F) to sixty
degrees Fahrenheit (60 DEG.F). "MMBtu" shall mean 1,000,000 Btu's.
"COGENERATION PLANTS" - Shall mean the cogeneration facilities which will
be constructed and operated by Partnership to be located at the British
Petroleum America Refinery in Ferndale, Washington and shall include other
cogeneration plants or independent power plants that may be constructed
between the Point of Receipt and the Point of Delivery.
"COMMERCIAL OPERATION DATE" - means the date that Partnership and Puget
Sound Power & Light Company acknowledge in writing that both units of the
Facility are capable of delivering energy on a continuous basis in
accordance with the provisions of the Agreement for Firm Power Purchase
between Partnership and Puget. Partnership shall within twenty-four (24)
hours of such date give written notice of such date to Cascade which date
shall be the Commercial Operation Date hereunder.
"CONSUMER PRICE INDEX" - Shall mean that index reported in the U.S.
Department of Labor, Bureau of Labor Statistics Report for the "ALL URBAN
CONSUMERS - U.S. CITY AVERAGE" - ALL ITEMS.
"CONTRACT YEAR" - The period of 12 consecutive months beginning at 2:00
p.m. Pacific Standard Time on the first day of the month following the
initial In-Service Date and each anniversary date thereafter.
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Agreement for Peak Gas Supply Service Page 3
"DAILY CONTRACT QUANTITY" or "DCQ" - The daily quantity of gas which
Cascade is obligated to transport for Seller pursuant to the Transportation
Agreement.
"DELIVERY POINT" - Shall mean the delivery points identified in Paragraph 7
of this Agreement.
"DEMAND RATE" - Shall mean the yearly rate independent of the volumes
actually transported as set forth in Sections.
"GAS SALES AGREEMENT" - Shall mean the Gas Sales Agreement between Tenaska
and Partnership dated August 1, 1992 as such may be amended or restated
from time to time.
"GROSS HEATING VALUE" - Shall mean the total calorific value expressed in
Btu's per cubic foot.
"IMPORT POINT" - Shall mean the point of interconnection of Westcoast and
Cascade located near Sumas, Washington.
"IN-SERVICE DATE" - Section 2.5.
"NORTHWEST" - Northwest Pipeline Corporation.
"PERSON" - An individual, corporation, voluntary association, joint stock
company, business trust, partnership or other entity.
"PGSS" - "Peak Gas Supply Service" - Section 2.1.
"PGSS GAS" - Shall mean PGSS Gas or Gas provided to Cascade by Seller under
this Agreement.
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Agreement for Peak Gas Supply Service
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"PGSS VOLUME" - Section 2.1.
"TRANSPORTATION AGREEMENT" - The agreement between the Parties dated
January 15, 1991, as amended, for Natural Gas Service Firm Transportation.
"WESTCOAST" - Section 7.
"WUTC" - Washington Utility and Transportation Commission
2. PGSS
2.1 Subject to the Operating Guidelines and other terms and conditions
hereinafter set forth, Seller shall provide to Cascade Peak Gas Supply
Service ("PGSS") up to 300,000 MMBtu ("PGSS Volume").
2.2 At any time upon request by Cascade, Seller will sell and deliver and
Cascade will purchase and accept gas for which Cascade has prepaid and
which has not been previously sold and delivered. Gas will be delivered on
any day at an hourly rate as set forth in the Operating Guidelines.
2.3 At any time that the undelivered volume of Gas for which Cascade has
prepaid falls below the PGSS Volume set forth in Section 2.1 above, Cascade
shall have the right to prepay for additional Gas up to the PGSS Volume set
forth in Section 2.1 above.
2.4 The total Gas volumes to be sold and delivered hereunder in any Contract
Year shall not exceed two (2) times the PGSS Volume set forth in Section
2.1 above, unless the Parties otherwise mutually agree.
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Agreement for Peak Gas Supply Service Page 5
2.5 Seller shall not be obligated to sell and deliver Gas until the first day
of the month following the date that the Cogeneration Plant achieves its
Commercial Operation Date ("In-Service Date").
3. INCREASES AND DECREASES IN PGSS VOLUME.
3.1 If at any time during the term of this Agreement, Seller shall increase its
DCQ under the Transportation Agreement, Cascade shall have the right, but
not the obligation, to increase the amount ("PGSS Volume Excess") of PGSS
Volume in effect at the time and the hourly rate of delivery of the Gas.
Cascade shall give notice to Seller of its election to increase the amount
of PGSS Volume no later than 45 days after Seller makes its election for
increasing its DCQ. Immediately upon such election by Cascade, the Parties
shall negotiate in good faith for the annual Demand Rate for the PGSS
Volume plus the PGSS Volume Excess based on the then current cost of
providing any required additional facilities, and for other terms and
conditions which will affect the delivery of the Gas, including the hourly
rate. In the event additional facilities are not required to accommodate
the PGSS Volume Excess, no change will be made in the Demand Rate in effect
at the time the PGSS Volume Excess becomes effective. In any event,
election by Cascade to increase the PGSS Volume shall not occasion any
change in the usage rate to be charged as service hereunder.
3.2 In the event Seller shall reduce its DCQ under the terms of the
Transportation Agreement, the amount of reduction in the hourly rate of
delivery of Gas and the PGSS Volume in effect at the time shall be
determined at the time based upon the reduction in the operating level of
the
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Cogeneration Plant and will be reflected through revision of this Agreement
and the Operating Guidelines. The amount of the reduction of the Demand
Rate shall be determined as follows:
(a) if the level of PGSS Volume has not been increased beyond the level in
effect as of the date of this Agreement or if the Demand Rate has not
been increased other than for escalations as provided for in Section
5, the Demand Rate shall not be reduced, or
(b) if the Demand Rate in effect at the time of the decrease has been
increased in addition to escalations because additional facilities
have been required because of the election of a PGSS Volume Excess as
provided for in Subsection 3.1, such Demand Rate shall be reduced but
the reduction shall be applied only to that portion of the Demand Rate
in excess of the Demand Rate that would otherwise be in effect by
reason of escalation pursuant to Section 5 ("Demand Rate Excess").
The total reduction in PGSS Volume Excess shall be applied
sequentially beginning with the most recent block of PGSS Volume
Excess. The reduction in the Demand Rate Excess shall be applied
sequentially beginning with the most recent Demand Rate Excess until
the total reduction in PGSS Volume Excess is covered.
(c) Any reduction in the Demand Rate shall be effective as of the
effective date of the reduction in PGSS Volume.
4. PREPAYMENT AND PRICING OF GAS. The prepayment for PGSS Volume and the
pricing therefor shall be dependent upon
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Agreement for Peak Gas Supply Service
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the timing and the nature of the prepayment as described below.
4.1 The total of the prepayment amount for PGSS Volume which Cascade desires to
purchase shall be the proportional or full delivered cost of Btu equivalent
amounts of fuel oil delivered to the Cogeneration Plant. Seller shall use
its best efforts to coordinate the purchase of fuel oil equivalent to
Cascade's PGSS Volume on a Gross Heating Value basis with the Cogeneration
Plant's purchase of fuels oil for its own use. To the extent such efforts
are successful, the total of the prepayment amount shall proportional share
of Cascade and the Cogeneration Plant of the total delivered cost of fuel
oil. To the extent such efforts are not successful, the total of the
prepayment amount shall reflect the actual cost of the fuel oil delivered
to the Cogeneration Plant. The total of the prepayment amount shall also
include reasonable direct costs and expense as actually incurred and paid
for transportation, administration, and amounts paid to third parties and
shall also include any consumption or other tax on oil equivalent to the
gross heating value of PGSS gas purchased by Cascade. Fuel oil quality
shall be consistent with the specifications of the Cogeneration Plant.
4.2 Prior to purchasing fuel oil, Seller will submit to Cascade an estimate of
the total of the prepayment amount recognizing that actual costs will be
used in determining the total prepayment amount to be paid by Cascade.
4.3 Prior to the In-Service Date, Cascade shall prepay for the PGSS Volume set
forth in Section 2.
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Agreement for Peak Gas Supply Service
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4.4 In the event that Cascade determines that the estimate submitted by Seller
pursuant to Section 4.2 is unacceptable, Cascade may secure bids from fuel
oil suppliers for the delivery of oil to the Cogeneration Plant. Cascade's
bids will specify fuel oil quality consistent with the specifications of
the Cogeneration Plant. If a bid submitted by Cascade represents the
lowest bid obtained from fuel oil suppliers and Seller does not accept such
bid then the low bid submitted by Cascade shall be used to determine the
total prepayment amount to be paid by Cascade.
5. RATE. In addition to the payments to be made pursuant to Sections 4 and 6,
Cascade will pay a yearly Demand Rate and a usage rate to Seller for PGSS.
The initial yearly Demand Rate shall be [CONFIDENTIAL INFORMATION OMITTED
AND FILED SEPARATELY WITH THE COMMISSION] and the initial usage rate shall
be [CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE
COMMISSION] per MMBtu of Gas actually delivered to Cascade. The Demand
Rate shall become due and owing and shall be billed and paid for on the In-
Service Date and on each anniversary date thereafter. On July 1, 1994 and
each July 1 thereafter, the Demand Rate and usage rate shall be adjusted by
one-half of the percentage change in the Consumer Price Index for the
twelve (12) months ending three (3) months prior to each July 1. In
addition, the rates to be charged by Seller shall be adjusted from time to
time to include any governmental levies imposed on Seller in providing
PGSS.
6. STANDBY CHARGE. In addition to the payments to be made pursuant to
Sections 4 and 5, Cascade shall pay to Seller each month a Gas Supply
Standby Charge equal to [CONFIDENTIAL INFORMATION OMITTED AND FILED
SEPARATELY WITH THE COMMISSION] per MMBtu times the volume of natural gas
transported by Cascade during the previous month pursuant to the
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Agreement for Peak Gas Supply Service
Page 9
Transportation Agreement. Each time that the Commodity Rate set forth
in the Transportation Agreement is adjusted pursuant to Section 2(e),
the Gas Supply Standby Charge shall be adjusted by the same
percentage.
7. DELIVERY POINTS. At Seller's option the "Delivery Point(s)" hereunder
shall be at either or both of the following: (a) the natural gas
transmission facilities at or near NE/4 NW/4 Section 11, Township 40N,
Range 4E, Whatcom County, Washington (generally referred to as the
Bellingham II Station), or (b) at Sumas, Washington from Westcoast
Transmission Company ("Westcoast"). Seller shall specify in advance of Gas
delivery its Delivery Points; provided, however, Seller may revise its
Delivery Points from time to time. The delivery of Gas hereunder on the
delivering pipeline's facilities shall be subject to the operational
procedures of the delivering pipeline.
8. DELIVERY PRESSURE. Seller shall deliver or cause the delivery of Gas
hereunder at the pressures in the systems of Westcoast or Northwest
Pipeline Corporation ("Northwest") as the case may be; provided, however,
Seller shall not be required to install compression to accomplish delivery
of Gas to Cascade.
9. QUALITY. The Gas sold and delivered by Seller to Cascade at the Delivery
Point(s) hereunder shall be of such quality to meet the applicable quality
specifications of Westcoast or Northwest depending upon the pipeline
delivering the Gas.
10. MEASUREMENT. Measurements and determination of heating value of the Gas
delivered hereunder shall be conducted or
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Agreement for Peak Gas Supply Service
Page 10
caused to be conducted by Cascade in conformity with specifications
prescribed by Westcoast or Northwest.
11. WARRANTY AND RISK. Seller warrants title to the Gas delivered hereunder
and the right to sell the same and that it is free from any liens,
encumbrances, and adverse claims. Seller agrees to pay, or cause to be
paid, to the Persons entitled thereto or to make settlement for all
royalties, overriding royalties, payments out of production and other like
charges, including import fees and taxes, arising out of or with respect to
the Gas sold and delivered hereunder. Seller shall defend, indemnify, and
hold Cascade, its parents, subsidiaries, and affiliates, and their
directors, officers, employees, and agents harmless against all suits,
actions, claims, liabilities, losses, damages, and expenses, including
costs of action and attorney's fees, arising from or out of any adverse
claims of any and all Persons to, in, or against the Gas delivered by
Seller to Cascade.
12. CONDITIONS PRECEDENT. This Agreement shall not become effective until:
(a) the Transportation Agreement becomes effective.
(b) Tenaska shall have executed an agreement with the owners of the
Cogeneration Plant by August 1, 1992 which will permit Seller to
fulfill its obligations under this Agreement.
(c) Cascade shall have with due diligence obtained all necessary approvals
of this Agreement and/or associated
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Agreement for Peak Gas Supply Service
Page 11
tariff schedules from the WUTC and the Oregon Public Utilities
Commission on or before September 1, 1992.
(d) Any one or all of the above dates may be extended by mutual agreement
of the Parties. If, after good faith negotiations, the Parties do not
agree to extend one or all of the dates, this Agreement may be
terminated, without liability one to the other, by either Party upon
written notice.
13. TERMINATION. The Agreement shall terminate as of the date of
termination of the primary term of the Transportation Agreement. Upon
termination, neither Party shall have any liability to the other
except for any amounts due and owing to the other pursuant to the
terms of this Agreement; provided, however, that if Seller exercises
its option to extend the primary term or subsequent terms of the
Transportation Agreement, Cascade shall have the right upon thirty
(30) days' prior written notice to continue this Agreement; provided
further, however, the provisions of Sections 6 and 25.8 shall survive
such termination by Cascade until the extended term of the
Transportation Agreement expires.
14. OPERATING GUIDELINES. The Parties agree that Operating Guidelines for
the rendition of PGSS are attached hereto as Exhibit A.
15. FAILURE TO DELIVER. In the event Gas is not delivered to Cascade upon
request in accordance with this Agreement, Seller's only liability,
unless Cascade terminates pursuant to Section 25.11.1, shall be to
reimburse Cascade for the difference between the: (1) the sum of the
usage
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Agreement for Peak Gas Supply Service
Page 12
rate and weighted average cost of Gas prepaid for by Cascade but not
sold and delivered at the time of the failure to deliver and; (2) the
cost of supplies purchased by Cascade in lieu of Gas. Cascade shall
cooperate in Seller's effort to limit its liability by purchase and
delivery of gas to cover any failure of Seller to deliver Gas. Such
cooperation shall be required only to the extent it does not
compromise Cascade's quality or availability of gas supply.
16. GAS SUPPLY AND TRANSPORTATION CONTRACTS. Seller has demonstrated to
Cascade that it (Seller) has executed firm contracts for the supply of Gas
and has provided for firm transportation of the Gas to the Delivery Point.
Seller shall maintain firm supply and transportation contracts with respect
to the Gas during the term of this Agreement sufficient to provide PGSS on
a reliable basis. Seller shall inform Cascade in writing in the event that
such gas supply contracts or transportation arrangements are proposed to be
amended so as to materially affect the deliverability of Gas to the
Delivery Point(s) or if such contracts are terminated.
17. NOMINATION. REPORTING AND BALANCE. Seller and Cascade agree that they
will cooperate with each other in complying with nomination, balancing and
reporting procedures required by Westcoast and Northwest.
18. MEASUREMENT AND TESTING PROCEDURES AND ERRORS.
(a) All measurements and testing of the Gas will be carried out by
Westcoast or Northwest or Cascade in accordance with Westcoast's,
Northwest's, or Cascade's normal
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Agreement for Peak Gas Supply Service
Page 13
standards and procedures. The Parties will accept all such
measurements and test results and use such for all purposes of this
Agreement, provided that any Party may at its expense audit and verify
Westcoast's or Northwest's measurements and test results within one
year after receipt of such and Seller may at its expense audit or
verify Cascade's measurement and test results within one year after
receipt of such. If a Party upon such audit determines that
Westcoast or Northwest or Cascade failed to carry out a measurement or
test in accordance with Westcoast's or Northwest's or Cascade's normal
standards and procedures, that Party shall promptly inform the other
Party of the disparity and the Parties shall review whether a mistake
was made and a correction is required.
(b) In the event an error is discovered in the amount billed in any
statement rendered by either Party, such error shall be adjusted
within thirty (30) days of the determination thereof but no adjustment
will be made for any error discovered more than two years after
receipt of such statement. In the event that any meter(s) shall be
out of service or found to be registering inaccurately, it shall be
adjusted at once to read as accurately as possible. If such
equipment is out of service or inaccurate such that it causes a
measurement error on a thermal basis of less than one percent, a
correction may be made if both Parties so agree. If such measurement
error is equal to or greater than one percent, on a thermal basis,
then the previous readings of such equipment shall be corrected to
zero error for a period agreed upon, or if not agreed upon, for a
period of one-half (1/2) of the elapsed time since the last test.
The volume of Gas delivered during such period shall be
<PAGE>
Agreement for Peak Gas Supply Service
Page 14
determined by Cascade using one of the following three methods:
(i) By using the registration of any check meters as may be installed
and accurately registering; or, in the absence of (i);
(ii) By correcting the error if the percentage of error is
ascertainable by calibration, tests or mathematical calculations,
or in the absence of both (i) and (ii);
(iii) By estimating volume, (utilizing data for deliveries to
Plant during periods when Cogeneration Plant experienced
similar operating conditions and when Cascade's meter was
registering accurately if such data is available).
19. WESTCOAST OR NORTHWEST PENALTIES. Any penalties payable to Westcoast or
Northwest arising out of the activities of the Parties under the Agreement,
including but not limited to failure to take delivery of Gas nominated or a
failure to supply Gas so nominated, shall be borne by the Party causing
that penalty to be incurred. If both Cascade and Seller have caused the
penalty to be incurred, the penalty shall be allocated based on each
Party's proportional share of the causation. Nothing in this paragraph 19
waives or compromises any Party's right to contest or defend any proposed
penalty assessed by Westcoast or Northwest.
20. TITLE TO AND LIABILITY FOR GAS. As between Seller and Cascade, liability
for, control of and title to all gas
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Agreement for Peak Gas Supply Service
Page 15
delivered hereunder will pass from Seller to Cascade at the Delivery Point.
Until such delivery, Cascade will have no liability either with respect to
any Gas deliverable under this Agreement or for any occurrence regarding
such Gas. After such delivery, Seller will have no liability either with
respect to any Gas delivered under this Agreement or for any occurrence
regarding such Gas.
21. REPRESENTATIONS.
21.1 TENASKA AND PARTNERSHIP'S REPRESENTATIONS. Tenaska and Partnership each
represents as to itself, as of the date hereof, as follows:
(a) Tenaska is a corporation duly incorporated and validly existing and
Partnership is a limited partnership duly formed and validly existing
and each has full power and authority to carry on its business, to
enter into this Agreement and any agreement or instrument referred to
or contemplated by this Agreement and to fully carry out their terms
subject to Section 12(b);
(b) Tenaska and Partnership hereto represent and warrant, that all
necessary Partnership or corporate action as appropriate has been
taken and authorization given to permit the execution, delivery and
performance of this Agreement as an Agreement which is valid and
binding on each of Tenaska and Partnership and enforceable against
Tenaska and Partnership in accordance with its terms.
(c) There is no litigation or proceeding pending, or to either Tenaska's
or Partnership's knowledge threatened, against Tenaska or Partnership
and Tenaska and Partnership do not
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Agreement for Peak Gas Supply Service
Page 16
know of or have any reason for believing there is any action,
proceeding, or inquiry which would materially affect their ability to
carry out their obligations hereunder;
(d) All rentals, fees and other payments which are due and owing with
respect to the Gas delivered under this Agreement either have been
paid prior to the date hereof, or will be paid promptly when due
during the term of this Agreement; and
(e) Tenaska and Partnership have no information or knowledge of any claim
which may affect their title to or ownership of the Gas to be
delivered hereunder.
21.2 CASCADE'S REPRESENTATIONS. Cascade represents to Seller, as at the date
hereof, as follows:
(a) Cascade is a corporation duly incorporated and validly existing and
has full power and authority to carry on its business, to enter into
this Agreement and any agreement or instrument referred to or
contemplated by this Agreement and to fully carry out its terms;
(b) Cascade has duly and validly authorized by all necessary corporate
action on its part the execution and delivery of this Agreement and
the completion of the transactions contemplated herein; and
(c) There is no litigation or proceeding pending, or to the knowledge of
Cascade, threatened, against Cascade, and Cascade does not know of or
have any reason for believing there is any action, proceeding or
inquiry which may
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Agreement for Peak Gas Supply Service
Page 17
materially affect its ability to carry out its obligations hereunder.
22. FORCE MAJEURE.
22.1 Provided that notice is given as required by Section 22.5 below, a
Party shall not be considered to be in default under this Agreement,
and its obligations hereunder shall be suspended (except for Cascade's
obligation to pay the Demand Rate and Gas Supply Standby Charge as
provided for in Sections 5 and 6 and to pay for Gas previously
delivered) in the event and for as long as such Party is prevented
from fulfilling its obligations by reason of Force Majeure.
22.2 The term "Force Majeure" shall be deemed for the purposes of this
Agreement to mean any cause or condition beyond a party's reasonable
control which such Party is unable to overcome by the exercise of
reasonable diligence including but not limited to storm, tornado,
landslide, washout, flood, lightning, earthquake, volcano, fire,
explosion, act of God, freezing of lines of pipe, breakdown or
accident to or the reasonable potential of breakdown or accident to
machinery, equipment or lines of pipe, civil disturbance, strike,
lockout, national emergency, restraint by court or public authority,
failure to act or delay in acting of civil, military or governmental
or regulatory authority, or a change in law or regulation with which
either Party subject to such change cannot reasonably comply. No
Party shall be required to accede or agree to any provisions not
satisfactory to it in order to settle or terminate a strike or other
labor disturbance. Force Majeure shall include the inability of
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Agreement for Peak Gas Supply Service
Page 17
materially affect its ability to carry out its obligations hereunder.
22. FORCE MAJEURE
22.1 Provided that notice is given as required by Section 22.5 below, a Party
shall not be considered to be in default under this Agreement, and its
obligations hereunder shall be suspended (except for Cascade's obligation
to pay the Demand Rate and Gas Supply Standby Charge as provided for in
Sections 5 and 6 and to pay for Gas previously delivered) in the event and
for as long as such Party is prevented from fulfilling its obligations by
reason of Force Majeure.
22.2 The term "Force Majeure" shall be deemed for the purposes of this Agreement
to mean any cause or condition beyond a reasonable control which such Party
is unable to overcome by the exercise of reasonable diligence including but
not limited to storm, tornado, landslide, washout, flood, lightning,
earthquake, volcano, fire, explosion, act of God, freezing of lines of
pipe, breakdown or accident to or the reasonable potential of breakdown or
accident to machinery, equipment or lines of pipe, civil disturbance,
strike, lockout, national emergency, restraint by court or public
authority, failure to act or delay in acting of civil, military or
governmental or regulatory authority, or a change in law or regulation with
which either Party subject to such change cannot reasonably comply. No
Party shall be required to accede or agree to any provisions not
satisfactory to it in order to settle or terminate a strike or other labor
disturbance. Force Majeure shall include the inability of
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Agreement for Peak Gas Supply Service
Page 18
Seller to perform because of a failure of delivery of Gas at the
Delivery Point or the failure of the Cogeneration Plant to convert to
oil so as to make Gas available for sale if such failure is caused by
an event of Force Majeure as described in this Section 22.2.
22.3 Force Majeure shall not include changes in market conditions, including but
not limited to changes that affect the cost or availability of Gas to be
supplied by Seller nor changes which affect the cost or demand for
electricity or oil.
22.4 The Party claiming Force Majeure shall exercise due diligence to remove any
disability to its performance caused by such Force Majeure with reasonable
promptness and dispatch. In the event that the Party claiming Force
Majeure may partially carry out such obligations, then such obligations of
the Party claiming Force Majeure shall be partially suspended, such partial
suspension to be commensurate with the reduction in the ability of the
Party claiming Force Majeure to carry out its obligations hereunder. Where
the obligation or operations, as the case may be, of the Party claiming
Force Majeure are wholly suspended, each Day during the continuation of
such suspension shall be a Full Force Majeure Day; and where such
obligations or operations, as the case may be, are partially suspended, a
commensurate fraction of each Day shall be a Partial Force Majeure Day.
22.5 (a) If Seller is prevented from fulfilling its obligations by reasons of
Force Majeure and the disability to its performance caused by such
Force Majeure is not permanently removed to Cascade's reasonable
satisfaction
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Agreement for Peak Gas Supply Service
Page 19
on or before 180 days from the date of notice given pursuant to
Section 22.6, Cascade shall have the right to terminate this Agreement
by giving written notice to Seller on or before 30 days after the date
of expiration of the 180 day period. Cascade's right to terminate
shall expire if not exercised within the 30 day period.
(b) If Cascade terminates this Agreement as aforesaid, the provisions of
Section 6 and Section 25.8 shall survive until the date of termination
of the Transportation Agreement, the provisions of Section 25.11.(d)
shall apply and Seller's sole liability shall be for amounts due and
owing to Cascade as of the date of termination.
22.6 A Party may not assert Force Majeure as an excuse for failure to perform
hereunder until the Party asserting failure to perform because of Force
Majeure notifies the other Party in writing or by telecopy or telegraph of
the commencement of the failure to perform due to Force Majeure. The
notice shall specify the nature of the Force Majeure, the date of its
commencement, the date of commencement of the failure to perform, the
measures to be taken to alleviate such Force Majeure and the estimated time
such corrective action is expected to take. If the notice is given within
seventy two (72) hours of the date of the commencement of the inability to
perform, the date of commencement of the inability to perform shall be as
set forth in the notice. If the notice is given subsequent to seventy two
(72) hours, the date of commencement of the date of inability to perform
shall be deemed to be seventy two hours prior to the date of the notice.
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Agreement for Peak Gas Supply Service
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23. REGULATORY COMPLIANCE. Except as otherwise specifically agreed in writing,
the Party who is responsible for obtaining regulatory approvals is also
responsible for complying with and maintaining such approvals and
agreements over the term of this Agreement. After approval of this
Agreement has been obtained pursuant to Section 12(c), neither Seller nor
Cascade shall contest or cause to be contested before any federal, state,
county or other governmental body, including but not being limited to the
WUTC or any successor governmental agency or department, or in any federal
or state court the justness, reasonableness, or lawfulness of any rates,
terms or conditions set forth in or established pursuant to this Agreement,
including but not limited to the justness, reasonableness, or lawfulness of
any such rates, terms or conditions under any federal, state or local
statute, rule, regulation, ordinance or judicial decision, or any
successor, supplemental or other acts. Cascade shall not be prohibited
from filing changes to its tariffs, including but not limited to, rates
charged under the schedules 665, 682 and 683 from time to time. To the
extent this Agreement conflicts with any tariff filed by Cascade, the terms
of this Agreement shall govern.
24. INDEMNIFICATION. Each Party will indemnify, defend and hold harmless the
other Party and its officers, employees and agents from any and all claims,
suits, actions, damages, costs (including, without limitation, reasonable
attorney fees) or liabilities to the extent arising from the indemnifying
Party's (a) failure to perform its obligations hereunder, or (b) breach of
its representations or covenants hereunder.
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Agreement for Peak Gas Supply Service
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25. MISCELLANEOUS.
25.1 NONWAIVER. Except as otherwise provided herein, the failure of either
Cascade or Seller to exercise any right granted it hereunder shall neither
impair nor be construed as a waiver of such Party's rights hereunder which
are exercisable at any subsequent time or times.
25.2 SUCCESSORS AND ASSIGNS. Any company which shall succeed by purchase,
merger, or consolidation to the properties, substantially as an entirety,
of either Cascade, Tenaska or Partnership, as the case may be, shall be
entitled to the rights and shall be subject to the obligations of its
predecessor in title under this Agreement. Any of the Parties may, without
relieving itself of its obligations under this Agreement, assign any of its
rights hereunder to a company with which it is affiliated. Except as
provided above, no assignment of this Agreement or any of the rights or
obligations hereunder shall be made by any Party unless there first shall
have been obtained the written consent thereto of the other Parties which
approvals shall not be unreasonably withheld. It is agreed, however, that
the restrictions on assignment contained in this paragraph shall not in any
way prevent any Party to this Agreement from pledging, assigning or
mortgaging its rights hereunder as security for its indebtedness without
the approval of the other Parties.
25.3 BENEFIT. This Agreement is for the benefit of and shall be binding upon
the respective successors and permitted assigns of the Parties.
25.4 RECORDS AND AUDIT. The Parties will keep and maintain true and accurate
books, records and accounts in respect
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Agreement for Peak Gas Supply Service
Page 22
of all statements, charges and computations made under this Agreement
and will preserve these books, records and accounts for a period of at
least six years after such statements, charges or computations are
made. Such records shall be kept and maintained in accordance with
generally accepted accounting principles applied consistently from
year to year and good industry practices and distinguishable from all
other books, records and accounts.
Each Party has the right, at its sole cost and upon providing
reasonable notice, to have a third party auditor, who is a member of a
national accounting firm, audit on such Party's behalf during normal
business hours the relevant accounts, books, records and charts of the
other Party to the extent necessary to verify the accuracy of any
statement, charge, computation or demand made under or pursuant to any
of the provisions of this Agreement. This right expires two years
after the termination of this Agreement.
If any error is discovered in any statement rendered hereunder, such
error will be adjusted within 30 days from the date of discovery, but
no adjustment will be made for any error discovered more than two
years after receipt of such statements.
25.5 MODIFICATION. No modification of the terms and provisions of this
Agreement shall be made except by the execution of written amendments
executed by Seller and Cascade.
25.6 INDEPENDENT CONTRACTORS. Nothing herein shall be construed as creating or
having created a partnership or
<PAGE>
Agreement for Peak Gas Supply Service
Page 23
joint venture between the Parties hereto, and no Party shall have the
power to bind or obligate the others to an agreement with a third
party except to the extent Seller has granted specific authority to
Cascade with respect to gas supply and nominations.
25.7 CONFIDENTIALITY. Cascade and Seller agree that the terms of this
Agreement or any draft thereof and any resulting transaction shall be
kept strictly confidential, except to the extent required by
applicable law, and except to the extent either Party is required to
disclose pertinent information concerning this Agreement to its
respective underwriters, lenders, regulators or Puget Sound Power and
Light Company within the normal course of business. If either Party
makes such disclosure, it shall advise the underwriters, lenders,
regulators or Puget Sound Power and Light Company that the information
disclosed is strictly confidential.
25.8 PAYMENTS.
Monthly bills shall be rendered on a calendar month basis.
The billing Party, on or before the tenth (lOth) day of each Month,
shall render to the owing Party a statement showing the quantity of
Gas delivered during the preceding Month and the amount due the
billing Party by the owing Party at the applicable price herein.
The owing Party shall pay the billing Party the amount invoiced on or
before twenty-five (25) days following the Month in which such gas was
delivered or fifteen (15) days after receipt of statement, whichever
is later.
<PAGE>
Agreement for Peak Gas Supply Service
Page 24
All payments due to Cascade shall be made by electronic funds transfer
to:
US Bank of Washington
ABA No. 125000105
for credit to:
Cascade Natural Gas Corporation
Acct. 1707330369
All payments due to Tenaska shall be made by electronic transfer to:
The Chase Manhattan Bank, N.A. New York
for credit to the account of:
Tenaska Gas Co.
All payments due to Partnership shall be made by electronic transfer
to:
The Chase Manhattan Bank, N.A., New York
for credit to the account of:
Tenaska Washington Partners, L.P.
Bills and notices shall be sent to the addresses set forth below
unless otherwise specified in writing.
Should either Cascade or Seller fail to pay on a timely basis all of
the amount of any billing for services rendered, or for any other
charges hereunder, interest thereon shall accrue at the then-effective
posted prime lending rate of The Chase Manhattan Bank, N.A., New York,
plus two (2) percent from the delinquent date until date of payment.
However, if one Party, in good faith, shall
<PAGE>
Agreement for Peak Gas Supply Service
Page 25
dispute the amount of any such billing or part thereof and shall pay
to the other Party such amounts as it concedes to be correct and at
any time thereafter within thirty (30) days of a demand made by the
other Party for the balance shall furnish a good and sufficient surety
bond in amount and with sureties satisfactory to the billing Party
conditioned upon the payment of any amounts ultimately found due upon
such billing after a final determination, which may be reached by
arbitration, then neither Party shall be entitled to suspend further
receipt or delivery of Gas unless and until default be made in the
conditions of such bond.
25.9 NOTICES. Notices under this Agreement shall be sent to:
CASCADE: Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington 98109
Attention: Vice President, Gas Supply
TENASKA: Tenaska Gas Co.
407 North 117th Street
Omaha, Nebraska 68154
Attention: President
PARTNERSHIP: Tenaska Washington Partners, L.P.
407 North 117th Street
Omaha, Nebraska 68154
Attention: President, Tenaska
Washington, Inc.
Any Party may change its address by written notice to that effect to
the other Parties. Notices given hereunder shall be deemed to have
been effectively given upon delivery, if sent by telecopy, telex, or
overnight delivery or five business days after deposit when deposited
with the United States Postal Service, registered or certified mail
with postage prepaid and
<PAGE>
Agreement for Peak Gas Supply Service
Page 26
directed to the post office address of the Parties as set out above.
25.10 SUBSEQUENT REGULATORY APPROVALS. To the extent that any modification,
amendment or extension of this Agreement requires approval from
governmental agencies, departments or regulatory bodies having
jurisdiction, such modification, amendment or extension shall not be
effective until such approval has been obtained in a form satisfactory
to both Parties as agreed in writing by them.
25.11
25.11.1 TERMINATION FOR SUBSTANTIAL BREACH
(a) In addition to other remedies that may be available, in the event
either Cascade or Seller shall be in substantial breach of the terms
of this Agreement, and shall not have cured such breach within 30 days
after notice of substantial breach by the other Party, the Party not
in breach shall have the right to terminate this Agreement at the end
of the cure period by notice to the Party in breach; provided,
however, if Seller fails to deliver Gas on three separate and distinct
occasions for reasons other than Force Majeure, (Force Majeure may be
counted as a failure to deliver Gas if reasonable efforts by Cascade
and Seller fail to obtain alternate supplies pursuant to Section 15),
Cascade shall have the right to terminate by written notice to Seller.
Any failure to deliver which could have been prevented by Seller
through the exercise of reasonable diligence shall not be considered
an event of Force Majeure.
<PAGE>
Agreement for Peak Gas Supply Service
Page 27
(b) If the Agreement is terminated because of breach by Cascade and if
Tenaska or the Partnership have constructed facilities as agreed to in
advance by Cascade and solely for Cascade's PGSS Volumes and not
otherwise required by Tenaska or the Partnership, Cascade will
reimburse Tenaska or the Partnership for those facilities at
depreciated book value less salvage value. If termination results
from a breach by Tenaska or Partnership, Cascade shall have no
reimbursement obligation to Tenaska or the Partnership.
(c) If Seller terminates the Agreement pursuant to this Section, the
provisions of Section 25.8 shall survive until the date of termination
of the Transportation Agreement. However, should Cascade terminate
the Agreement pursuant to this Section, the provisions of Section 6
and Section 25.8 shall survive until the date of termination of the
Transportation Agreement.
(d) Other than pursuant to Section 15, neither Cascade nor Seller hall be
entitled to recover from the other Party for loss of use or for other
punitive, special, incidental or consequential damages suffered as a
result of or breach of any provision of this Agreement.
25.12 GOVERNING LAWS. The laws of the state of Washington shall govern this
Agreement and the rights and the obligations of the Parties hereunder,
and in the event of any action brought hereunder, venue shall be
proper in the county of King, state of Washington.
25.13 CONDUCT OF OPERATIONS. Each Party will conduct its operations related
to this contract in a careful and
<PAGE>
Agreement for Peak Gas Supply Service
Page 28
prudent manner in accordance with the terms of this contract, good industry
practices and all applicable present and future valid laws, orders,
directives, rules and regulations of duly constituted authorities having or
purporting to have jurisdiction over such operations.
25.14 FURNISHING OF INFORMATION. Upon the written request by one Party the
other will furnish information on a timely basis which the Party may
reasonably require in respect of gas to be delivered hereunder or
other matters relating to this contract.
25.15 ENTIRE AGREEMENT. The contract constitutes the entire agreement
between the Parties with respect to the matters set forth hereunder.
This contract may be executed in any number of counterparts each of
which shall be deemed to be an original of this contract.
25.16 SEVERABILITY. If any provision hereof shall be found to be
inoperative or in violation of any law or regulation, only that
provision shall be deleted from this Agreement, and the remainder of
this Agreement hall not be affected.
26. ARBITRATION. Any dispute or claim arising out of this Agreement shall be
settled by arbitration. Arbitration proceedings shall be commenced by the
delivery by either Party to the other of written notice demanding
arbitration. The matter shall be submitted to such disinterested
arbitrator as shall be agreed upon by the Parties. The arbitrator shall
determine the rules to govern the arbitration proceeding. In the event the
Parties are unable to agree upon an arbitrator within ten calendar days of
the date a notice requesting arbitration
<PAGE>
Agreement for Peak Gas Supply Service
Page 29
is delivered, then arbitration shall be conducted in accordance with
the Commercial Arbitration Rules of the American Arbitration
Association ("AAA"). If arbitration is conducted pursuant to the
rules of the AAA, the controversy or claim shall be decided by a board
of three arbitrators. The Parties each shall select one arbitrator
within ten days of a demand for arbitration being made or, in the
event of a Party's failure to so elect, an arbitrator shall be named
for that Party by the AAA. Within ten days of their selection, the
two arbitrators so selected shall select a third arbitrator from the
National Panel of Arbitrators maintained by the AAA or as they
otherwise shall agree. Any arbitration hearing shall be held at
Seattle, Washington, unless the Parties agree otherwise. Any award
rendered by arbitration shall be final and binding on the Parties, and
judgment thereon may be entered in King County Superior Court or any
other court of competent jurisdiction. Notwithstanding any
arbitration rules to the contrary, the award of the arbitrator(s) must
be made no later than six (6) months following the date on which the
arbitrator(s) are appointed. The arbitrator(s) shall have authority
and discretion to award costs and reasonable attorney's fees to the
prevailing Party.
27. ATTORNEY'S FEES. In the event it becomes necessary for either Party to
obtain the services of an attorney for the purposes of enforcement of any
of the provisions of this Agreement, the prevailing Party shall be entitled
to reimbursement of all reasonable attorney's fee and collection costs as
the arbitrator, the trial judge or the appellate court may judge reasonable
in the arbitration,
<PAGE>
Agreement for Peak Gas Supply Service
Page 30
the action and the appeal, if any, along with statutory costs,
disbursements, and applicable interest.
28. STATUS OF TENASKA AND PARTNERSHIP AS SELLER.
28.1 Subject to the provisions of this Section 28, Tenaska and Partnership shall
be referred to collectively as "Seller" throughout this Agreement and shall
be jointly and severally liable for the duties, obligations and liabilities
of Seller hereunder.
Cascade, Tenaska and Partnership each further acknowledges and agrees
that as between Tenaska and Partnership, Partnership is the intended
beneficiary of this Agreement.
28.2 In the event that the Gas Sales Agreement is terminated for any reason,
each of Tenaska and Partnership shall have the right, upon sixty (60) days
written notice, to terminate this Agreement as to Tenaska only but such
termination shall not relieve Tenaska of any of its responsibilities under
this Agreement.
28.3 Notwithstanding any other provision of this Agreement to the contrary, all
actions to be taken by Seller with respect to this Agreement, including but
not limited to entering into amendments to this Agreement, shall require
the written agreement of Tenaska, Partnership and Cascade, and Cascade
shall not rely upon any action taken by Seller unless each of Tenaska and
Partnership has agreed in writing to such action.
<PAGE>
Agreement for Peak Gas Supply Service
Page 31
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly
executed in several counterparts by their proper officers thereunto duly
authorized as of the date first hereinabove written.
ATTEST: CASCADE: CASCADE NATURAL GAS
CORPORATION
// Yvvone Fourno // By: //W. Brian Matsuyama//
Title: President
ATTEST: TENASKA; TENASKA GAS CO
//Ronald Quexon, Secretary// By: //Larry V. Pearson//
Title: Vice President
PARTNERSHIP:TENASKA WASHINGTON
PARTNERS, L.P.
By: Tenaska Washington I, L.P.
Managing General Partner
By: Tenaska Washington, Inc.
Managing General Partner
ATTEST:
//Douglas A. Troupe// By: //Thomas E. Hendrick//
Assistant Secretary Title: Vice President
<PAGE>
EXHIBIT A
TENASKA GAS CO.
PEAK GAS SUPPLY SERVICE
FOR
CASCADE NATURAL GAS CORPORATION
OPERATING GUIDELINES
1. Seller and Cascade will have responsible personnel available at all times
to accept and implement operational communications concerning PGSS service.
Communications will be by telephone voice communication followed by a
confirming facsimile or by facsimile if voice contact cannot be
established.
2. Cascade shall have the right to initiate PGSS or change the volume of the
PGSS being received once per day. Seller and Cascade may mutually agree
to initiate or change PGSS volumes more than once per day.
3. Cascade shall give as much notice as is possible, but not less than four
(4) hours, prior to initiating or terminating PGSS or not less than two (2)
hours prior to changing the PGSS volume.
4. Cascade or the transporter delivering gas to Cascade shall be responsible
for the measurement of gas taken during the period of PGSS. The volume of
gas actually taken by Cascade during such a period shall reduce the PGSS
gas for which Cascade has prepaid and which has not been previously
delivered to Cascade.
5. Seller shall cause the cogeneration plant to transition its fuel
consumption from gas to oil or oil to gas, as the case may be, as requested
by Cascade. However, the Parties recognize and agree that during such
transition, the Cogeneration Plant Operator shall use its judgement and
experience to make such transition expeditiously and, in most cases, within
one hour.
6. Cascade shall nominate periods of six or more hours for PGSS. The Parties
may mutually agree to a shorter period for PGSS.
7. Seller shall cause the Cogeneration Plant to make Gas available in whole
turbine units as such are running at the time of the request, approximately
25,000 MMBtu per day per turbine unit. The initial cogeneration plant
contemplates having two combustion turbines. Hence, Cascade may request
one unit or both units be dispatched to oil or returned to gas and Seller
will comply with such request within the confines of the PGSS service.
<PAGE>
8. Seller and Cascade recognize and agree that some gas will be used during
periods when Cascade is receiving PGSS. These gas uses are not switchable
to oil and will amount to less than 6,500 MMBtu per day and the volume of
Gas requested by Cascade may be reduced by such amount.
9. In the event that the Cogeneration Plant is not operating at the time of a
request by Cascade for PGSS, Seller will immediately request its
supplier(s) and transporters to begin delivering gas for Cascade's use.
The Parties recognize that nomination time constraints will impact the
effectiveness of using supply nominations to serve PGSS and any PGSS
nomination shall be consistent with normal scheduling of gas sales and
transportation.
10. In the event that Seller's gas supply has been resold to a third party at
the time of a request by Cascade for PGSS, Seller will immediately notify
its buyer that the gas sale has been curtailed and Seller will make the gas
available to Cascade as PGSS. Seller will not resell any of its gas
supplies under agreements whose terms would preclude Seller from complying
with all responsibilities and obligations of the PGSS Agreement.
11. Penalties incurred by Cascade from West Coast Energy, Inc. or Northwest
Pipeline Corporation as a result of nomination imbalance or unauthorized
overrun, will be passed on directly to those customer(s) or groups of
customer(s) whose take levels contribute to the imposition of the penalty.
Such penalties shall be allocated among such customers, including Cascade's
system supply customers, in proportion to the nomination imbalance or
unauthorized overrun associated with each customer or group of customers.
12. Thermal equivalence will be based on the actual gross heating value of the
fuel oil purchased by Seller, as the thermal equivalent of PGSS Gas, as
verified by invoices or delivery tickets and will determine the inventory
level of PGSS Gas owned by Cascade. Consumption of PGSS Gas will be
determined by the actual MMBtu's delivered to Cascade by Seller's producers
and transporters during period of PGSS usage.
<PAGE>
TENASKA AND AFFILIATES
ARE RELOCATING THE
OMAHA CORPORATE OFFICES
Effective April 18, 1994
(Office will be closed Friday, April 17)
THE NEW ADDRESS IS:
1044 N. 115 St., Suite 400
Omaha, NE 681544-4446
Telephone (402) 691-9500
ALL PHONE AND FAX NUMBERS
REMAIN THE SAME
(except below)
TENASKA INTERNATIONAL DIVISION
NEW DIRECT DIAL NUMBERS:
General (402) 691-9500 Lyle Bauer (402) 691-9566
Fax (402) 691-9570 Tony Fontana (402) 691-9567
<PAGE>
AGREEMENT
FOR PEAKING GAS SERVICE
(PGS)
This Agreement ("Agreement") dated as of November 22, 1991 sets forth the
understanding of CASCADE NATURAL GAS CORPORATION ("Cascade") and LONGVIEW FIBRE
COMPANY ("Longview") for Peaking Gas Service to Cascade for the natural gas
("Gas") to be furnished by Longview. Together Cascade and Longview are
sometimes referred to as the "Parties".
1. DEFINITIONS.
Capitalized terms used in this Agreement shall have the respective
meanings, as defined below:
"BTU" - Shall mean the amount of heat required to raise the temperature of
one pound of water from fifty-nine degrees Fahrenheit (59 DEG.F) to sixty
degrees Fahrenheit (60 DEG.F).
"CONTRACT YEAR" - Shall mean the period of 12 consecutive months beginning
at 2:00 pm. Pacific Standard Time on October 1, 1991 and each anniversary
date thereafter.
"NORTHWEST" - Shall mean Northwest Pipeline Corporation.
"PERSON" - Shall mean an individual, corporation, voluntary association,
joint stock company, business trust, partnership or other entity.
"PGS" - Shall mean "Peaking Gas Service" - as defined in Section 2.1.
"PGS GAS" - Shall mean PGS Gas or Gas provided to Cascade by Longview
under this Agreement.
"PLANT" - Shall mean Longview's pulp and paper mill near Longview,
Washington.
<PAGE>
Agreement for Peaking Gas Supply Service
Page 2
"PGS VOLUME" - Defined in Section 2.1.
"THERM" - Shall mean 100,000 Btu's.
"WUTC" - Shall mean the Washington Utilities and Transportation Commission
2. PGS.
2.1 Subject to the Operating Guidelines and the other terms and conditions of
this Agreement, Longview shall provide to Cascade Peaking Gas Service
("PGS") up to 3,000,000 Therms (the "PGS Volume") annually during each
Contract Year.
2.2 At any time upon request by Cascade, Longview will make available to
Cascade Gas up to the PGS Volume. Gas will be delivered on any day, up to
150,000 Therms per day, at an hourly rate as set forth in the Operating
Guidelines.
2.3 Longview will provide PGS by reducing the natural gas consumption of the
Plant at Cascade's request according to the Operating Guidelines.
2.4 Longview hereby relieves Cascade of its obligation to serve Longview
including using Cascade's firm pipeline capacity, as represented in the
Firm Pipeline Capacity Natural Gas Service Agreement, dated December 7,
1989 between the Parties, in an amount equivalent to and concurrent with
the PGS requested by Cascade under the Operating Procedures.
2.5 Cascade will utilize the PGS Gas as a source for its firm customers.
3. REGULATIONS. This Agreement is subject to all applicable provisions set
forth in Cascade's tariff as filed with the WUTC as in effect from time to
time, and to orders, rules and regulations of duly constituted authorities
having jurisdiction over either or both Cascade and Longview.
<PAGE>
Agreement for Peaking Gas Supply Service
Page 3
4. PGS FEE. Cascade will pay a yearly fee ("PGS Fee") to Longview for PGS.
The initial PGS Fee shall be [CONFIDENTIAL INFORMATION OMITTED AND FILED
SEPARATELY WITH THE COMMISSION] per Contract Year. The PGS Fee shall
become due and owing and shall be billed and paid for on a monthly basis at
the rate of 1/12 of the PGS Fee per month, on the 10th day of each month
commencing October, 1991. The PGS Fee shall be adjusted by mutual
agreement of the Parties to ensure the PGS Fee is comparable to least cost
alternative sources of peaking service reasonably available to Cascade. If
the Parties fail to agree on the PGS Fee after the first Contract Year,
such revised PGS Fee shall be determined by arbitration under paragraph 21
below. The PGS Fee shall be payable regardless of the level of PGS use by
Cascade.
5. GAS SUPPLY COSTS: ALTERNATE FUEL. In addition to the PGS Fee, Cascade shall
be responsible for direct payment of all supply costs for Gas including
pipeline transportation during PGS usage. Longview shall be responsible
for all alternate fuel costs at the Plant during PGS usage.
6. TERMINATION. This Agreement shall terminate as of the date of termination
of the Firm Pipeline Capacity Natural Gas Service Agreement, dated
December 7, 1989 between the Parties. Upon termination, neither Party
shall have any liability to the other except for any amounts due and owing
to the other pursuant to the terms of this Agreement.
7. OPERATING GUIDELINES. The Parties agree that Operating Guidelines for the
rendition of PGS are attached hereto as Exhibit A and are incorporated into
this Agreement by reference.
8. INDEMNIFICATION. Each Party will indemnify, defend and hold harmless the
other Party and its officers, employees and agents from any and all
claims, suits, actions, damages, costs (including, without limitation,
reasonable attorney fees) or liabilities to the extent arising from the
indemnifying Party's (a) failure to perform its obligations hereunder, or
(b) breach of its representations or covenants hereunder.
<PAGE>
Agreement for Peaking Gas Supply Service Page 4
9. NONWAIVER. Except as otherwise provided herein, the failure of either Party
to exercise any right granted it hereunder shall neither impair nor be
construed as a waiver of such Party's rights hereunder which are
exercisable at any subsequent time or times.
10. SUCCESSORS AND ASSIGNS. Any Person which shall succeed by purchase, merger,
or consolidation to the properties, substantially as an entirety, of either
Cascade or Longview, as the case may be, shall be entitled to the rights
and shall be subject to the obligations of its predecessor in title under
this Agreement. Either Party may without relieving itself of its
obligations under this Agreement, assign any of its rights thereunder to a
company with which it is affiliated. Except as provided above, no Party
shall assign of this Agreement or any of the rights or obligations
hereunder unless there first shall have been obtained the written consent
thereto of the other party, which approvals shall not be unreasonably
withheld. It is agreed, however, that the restrictions on assignment
contained in this paragraph shall not in any way prevent either Party to
this Agreement from pledging, assigning or mortgaging its rights hereunder
as security for its indebtedness without the approval of the other Party.
11. BENEFIT. This Agreement is for the benefit of and shall be binding upon the
respective successors and permitted assigns of the Parties.
12. RECORDS AND AUDIT. The Parties will keep and maintain true and accurate
books, records and accounts in respect of all statements, charges and
computations made under this Agreement and will preserve these books,
records and accounts for a period of at least two years after such
statements, charges or computations are made. Such records shall be kept
and maintained in accordance with generally accepted accounting principles
applied consistently from year to year, and good industry practices, and
distinguishable from all other books, records and accounts.
<PAGE>
Agreement for Peaking Gas Supply Service
Page 5
Each Party has the right, at its sole cost and upon providing reasonable
notice, to have a third party auditor, which is a national accounting
firm, audit on such Party's behalf during normal business hours the
relevant accounts, books, records and charts of the other Party to the
extent reasonably necessary to verify the accuracy of any statement,
charge, computation or demand made under or pursuant to any of the
provisions of this Agreement. This right expires two years after the
termination of this Agreement.
If any error is discovered in any statement rendered hereunder, such error
will be adjusted within 30 days from the date of discovery, but no
adjustment will be made for any error discovered more than two years after
receipt of such statements.
13. MODIFICATION. No modification of the terms and provisions of this Agreement
shall be made except by the execution of written amendments executed by
Longview and Cascade.
14. INDEPENDENT CONTRACTORS. Nothing herein shall be construed as creating or
having created a partnership or joint venture between the Parties hereto,
and neither Party shall have the power to bind or obligate the other to an
agreement with a third party except to the extent Longview has granted
specific authority to Cascade with respect to gas supply and nominations.
15. CONFIDENTIALITY. Cascade and Longview agree that the terms of this
Agreement or any draft thereof and any resulting transaction shall be kept
strictly confidential, except to the extent required by applicable law,
and except to the extent either Party is required to disclose pertinent
information concerning this Agreement to its respective lenders or
regulators within the normal course of business. If either Party makes
such disclosure, it shall advise the lenders or regulators that the
information disclosed is strictly confidential.
<PAGE>
Agreement for Peaking Gas Supply Service Page 6
16. NOTICES. Notices under this Agreement shall be sent to:
CASCADE: Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington 98109
Attention: Director, Gas Supply
Fax No. (206) 624-7215
LONGVIEW: Longview Fibre Co.
P. O. Box 639
Longview, WA 98632
Attention: Mark Hoehne, Assistant Vice President
Fax No. (206) 425-3116
Either Party may change its address by written notice to that effect to the
other Party. Notices given hereunder shall be deemed to have been
effectively given upon delivery, if sent by telecopy, telex, or overnight
delivery or five business days after deposit, when deposited with the
United States Postal Service, with postage prepaid and directed to the
post office address of the Parties as set out above.
17. TERMINATION FOR SUBSTANTIAL BREACH. In addition to other remedies that may
be available, in the event either Party shall be in substantial breach of
the terms of this Agreement, and shall not have cured such breach within
30 days after notice of substantial breach by the other Party, the Party
not in breach shall have the right to terminate this Agreement at the end
of the cure period by notice to the Party in breach. Neither Party shall
be entitled to recover from the other Party for loss of use or for other
punitive, special, incidental or consequential damages suffered as a
result of or breach of any provision of this Agreement.
18. GOVERNING LAWS. The laws of the state of Washington shall govern this
Agreement and the rights and the obligations of the Parties hereunder, and
in the event of any action brought hereunder, venue shall be proper in the
county of King, state of Washington.
<PAGE>
Agreement for Peaking Gas Supply Service Page 7
19. ENTIRE AGREEMENT. This contract constitutes the entire agreement between
the Parties with respect to the matters set forth hereunder. This
Agreement may be executed in any number of counterparts each of which
shall be deemed to be an original.
20. SEVERABILITY. If any provision hereof shall be found to be inoperative or
in violation of any law or regulation, only that provision shall be
deleted from this Agreement, and the remainder of this Agreement shall not
be affected.
21. ARBITRATION. Any dispute or claim arising out of this Agreement shall be
settled by arbitration. Arbitration proceedings shall be commenced by the
delivery by either Party to the other of written notice demanding
arbitration. The matter shall be submitted to such disinterested
arbitrator as shall be agreed upon by the Parties. The arbitrator shall
determine the rules to govern the arbitration proceeding. In the event the
Parties are unable to agree upon an arbitrator within ten calendar days of
the date of notice requesting arbitration is delivered, then arbitration
shall be conducted in accordance with the Commercial Arbitration Rules of
the American Arbitration Association ("AAA"). If arbitration is conducted
pursuant to the rules of the AAA, the controversy or claim shall be
decided by a board of three arbitrators. The Parties each shall select one
arbitrator within ten days of a demand for arbitration being made or, in
the event of a Party's failure to so select, an arbitrator shall be named
for that Party by the AAA. Within ten days of their selection, the two
arbitrators so selected shall select a third arbitrator from the National
Panel of Arbitrators maintained by the AAA or as they otherwise shall
agree. Any arbitration hearing shall be held at Seattle, Washington,
unless the Parties agree otherwise. Any award rendered by arbitration
shall be final and binding on the Parties, and judgment thereon may be
entered in King County Superior Court or any other court of competent
jurisdiction. Notwithstanding any arbitration rules to the contrary, the
award of the arbitrator(s) must be made no later than six (6) months
following the date on which the arbitrator(s) are appointed. The
arbitrator(s) shall have authority and discretion to forward costs and
reasonable attorney's fees to the prevailing Party.
<PAGE>
Agreement for Peaking Gas Supply Service
Page 8
22. ATTORNEY'S FEES. In the event it becomes necessary for either Party to
obtain the services of an attorney for the purposes of enforcement of any
of the provisions of this Agreement, the prevailing Party shall be
entitled to reimbursement of all reasonable attorney's fee and collection
costs as the arbitrator, the trial judge or the appellate court may judge
reasonable in the arbitration, the action and the appeal, if any, along
with statutory costs, disbursements, and applicable interest.
IN Witness WHEREOF, the Parties hereto have caused this Agreement to be duly
executed in several counterparts by their proper officers thereunto duly
authorized as of the date first hereinabove written.
CASCADE NATURAL GAS CORPORATION
By________________________________________________
Title: Melvin C. Clapp
Chief Executive Officer
LONGVIEW FIBRE COMPANY
By:________________________________________________
Title: Mark E. Hoehne
Assistant Vice President
<PAGE>
EXHIBIT A
LONGVIEW FIBRE COMPANY
PEAKING GAS SERVICE
FOR
CASCADE NATURAL GAS CORPORATION
OPERATING GUIDELINES
1. Longview and Cascade will have responsible personnel available at all times
to accept and implement operational communications concerning PGS service.
Communications will be by telephone voice communication wherein Cascade's
dispatcher will advise Longview's Turbine Operator that he wishes to
discuss gas delivery, under PGS Service, with the Shift Engineer. Actual
load changes will be made after communication between Cascade Dispatcher
and Longview Shift Engineer.
2. Cascade shall have the right to initiate PGS or change the volume of the
PGS being received once per day. Longview and Cascade may mutually agree
to initiate or change PGS volumes more than once per day.
3. Cascade shall give as much notice as is possible, but not less than four
(4) hours, prior to initiating or terminating PGS or not less than two (2)
hours prior to changing rate of taking PGS.
4. Cascade or the transporter delivering gas to Cascade shall be responsible
for the measurement of gas taken during the period of PGS.
5. Longview shall cause the Plant to transition its fuel consumption from gas
to an alternate or an alternate to gas, as the case may be, as requested
by Cascade. However, the Parties recognize and agree that during such
transition, Longview shall use its judgement and experience to make such
transition expeditiously and, in most cases, within two hours.
6. Cascade shall nominate periods of twelve (12) or more hours for PGS. The
Parties may mutually agree to a shorter period for PGS.
7. Cascade may nominate rates of taking PGS from 3,000 to 6,250 therms per
hour.
8. As of the date of this Peaking Gas Service Agreement, the parties recognize
that Longview Fibre is purchasing supplies for use at its plant from
Cascade, and that it is Cascade's intent to contract for firm gas supplies
that can be taken in conjunction with the firm capacity being provided as
Peaking Gas Service. This contract will not preclude Longview Fibre from
contracting directly with a third party for its supplies at some future
time; provided, that in Cascade's reasonable opinion gas service pursuant
to such contracts is comparable in reliability to firm contracts entered
provided, that such change in suppliers by Longview Fibre shall occur at
the time of termination of the then current Cascade gas supply contract or
contracts entered into for use with the Peaking Gas Service, unless
otherwise agreed to by Cascade. Longview Fibre will be solely responsible
for the full cost of all gas purchased from third parties, except as
specifically provided in this Peaking Gas Service Agreement.
<PAGE>
PREARRANGED CAPACITY RELEASE OF
FIRM NATURAL GAS TRANSPORTATION AGREEMENTS
This Capacity Release of Firm Natural Gas Transportation Agreements
("Agreement") is made as of this 30th day of November, 1993 by and among Cascade
Natural Gas Corporation, a Washington corporation with its registered office in
Seattle, Washington ("Cascade") and Tenaska Gas Co. ("Gas Co."), a Nebraska
corporation, and Tenaska Washington Partners, L.P. ("Partnership"), a Washington
limited partnership (Gas Co. and Partnership collectively referred to as
"Tenaska").
WITNESSETH:
WHEREAS, pursuant to certain Natural Gas Transportation Agreements between
Northwest Pipeline Corporation ("Northwest") and Cascade, dated the 27th day of
August, 1992 ("Northwest Transportation Agreements"), copies of which are
attached hereto as Attachment A and Attachment B, Northwest provides firm
transportation of natural gas to Cascade; and
WHEREAS, Cascade, Gas Co. and Partnership have entered into a Natural Gas
Purchase and Sale Agreement dated August 1, 1992 (the "Buy/Sell Agreement")
which contains provisions for Cascade to utilize the Northwest Transportation
Agreements to transport certain gas purchased by Cascade from Tenaska to
delivery points under the Northwest Transportation Agreements where such gas
would be resold to Tenaska; and
WHEREAS, Cascade has "grandfathered" the Buy/Sell Agreements pursuant to the
Northwest tariff in order to comply with the Federal Energy Regulatory
Commission ("F.E.R.C.") Order 636; and
WHEREAS, Partnership is constructing a cogeneration facility in the Ferndale,
Washington area (the "Facility"), and Tenaska could utilize the Northwest
Transportation Agreements to provide transportation service to the Facility
other than through the use of the Buy/Sell Agreement; and
<PAGE>
(2)
WHEREAS, Cascade wishes to permanently release, and Tenaska wishes to accept,
all of the rights and obligations under the Northwest Transportation Agreements
pursuant to the terms and conditions of this Agreement;
NOW, THEREFORE, in consideration of the mutual covenants and agreements
contained herein, the receipt of which is hereby acknowledged, and intending to
be legally bound and to bind their successors and assigns, Gas Co., Partnership
and Cascade (the "Parties" hereto; each is a "Party") agree as follows:
1. Cascade hereby agrees to hold and maintain the Northwest Transportation
Agreements in accordance with the terms and conditions set out herein and
to permanently release unto Tenaska, and its permitted successors and
assignees, all of Cascade's right, title and interest in, to and under the
Northwest Transportation Agreements, including the right to renew or extend
the term of the Northwest Transportation Agreements, effective as of the
Capacity Release Date, such assignment and transfer being hereafter
referred to as the "Capacity Release".
2. (i) This Agreement shall be in full force and effect and binding upon
Cascade and Tenaska as of the date hereinabove stated.
(ii) Subject to subparagraph 2(v), the effective date (the "Capacity
Release Date") of Cascade's release and of Tenaska's acceptance and
assumption pursuant to Paragraph 3 of this Agreement shall be
April 1, 1994.
(iii) Thirty (30) days prior to the minimum notice period required by
Northwest to allow for a capacity release on the Capacity Release
Date, Cascade shall deliver a copy of this Agreement to Northwest
and shall authorize Northwest to post any
<PAGE>
(3)
necessary information on Northwest's Electronic Bulletin Board in
accordance with Northwest's F.E.R.C. approved tariff to give
effect to the Capacity Release in the form of a capacity release
to a Prearranged Replacement Shipper (as defined in the Northwest
tariff).
(iv) Prior to the posting on Northwest's Electronic Bulletin Board of
this Agreement, Tenaska shall fulfill all requirements of Tenaska
in its role as a Prearranged Replacement Shipper under the
capacity release provisions of the Northwest tariff, including
the execution of a new service agreement with Northwest to
permanently replace the Northwest Transportation Agreements
("Capacity Release Service Agreement(s)") and its demonstration
of creditworthiness to Northwest in accordance with the Northwest
tariff.
(v) If, at ten days prior to the Capacity Release Date:
(a) the Parties have not fulfilled their obligations under
Paragraph 2(iii) and 2(iv) of this Agreement such that the
Capacity Release shall be capable of being given effect
without the necessity of waiting for competing bids for the
Capacity Release to be submitted, or
(b) the Parties, together with Partnership's lenders for the
Facility, have not executed amendments to the Consent and
Agreement dated November 25, 1992 dealing with the Buy/Sell
Agreements in order to provide for the termination of the
Buy/Sell Agreement and for the inclusion of this Agreement
within the provisions of the Consent and Agreement,
then the Parties shall cooperate, in good faith, to set a new
Capacity Release Date, which date shall be the first of a month
that would allow for the Parties to comply with subparagraphs
2(iii) - (v) of this Agreement.
<PAGE>
(4)
(vi) The Capacity Releases shall be given effect pursuant to the
Northwest rules and regulations approved by the F.E.R.C. pursuant
to F.E.R.C. Order No. 636, as applicable to prearranged
agreements for capacity release, and the capacity releases shall
remain subject to all applicable F.E.R.C. rules and regulations
and, to the extent necessary, approval by Northwest. The
Capacity Releases shall be done on the basis of the full tariff
rate applicable to the Northwest Transportation Agreements
subject to the capacity release. The Capacity Releases shall be
done for the full term of the Northwest Transportation Agreements
subject to the release, including the right to renew or extend
the term of the Northwest Transportation Agreements, and shall be
a "Permanent Capacity Release" (as defined in the Northwest
tariff) without any provisions for the reversion of the Firm
Transportation Agreements to Cascade at the end of the term of
the Northwest Firm Transportation Agreements subject to the
Capacity Release.
(vii) The Parties, giving due consideration to the Partnership Facility
financing and the regulatory procedures necessary for the
Capacity Release of the Northwest Transportation Agreements,
hereto agree to execute and deliver such other documents and
certificates as are reasonably necessary to carry out the
purposes of this Agreement, including but not limited to, in the
case of Tenaska, the execution and delivery of new Capacity
Release Service Agreement(s) with Northwest confirming that
Tenaska has met the credit requirements of Northwest for the
purposes of the Capacity Release and Tenaska is capable of being
accepted as a contracting party in the Northwest Capacity Release
Service Agreement(s) in place and instead of Cascade from and
after the Capacity Release Date. The Parties agree to endeavour
in good faith and with due diligence to comply with the
requirements of Northwest to effectuate the capacity release
described herein and the substitution of Tenaska to Cascade's
position in the Northwest Transportation Agreements or their
replacement Northwest Service Agreements.
<PAGE>
(5)
(viii) Upon the final, effective completion of the Capacity Release
described in this Agreement, the Buy/Sell Agreement between
Cascade, Gas Co. and Partnership shall be terminated and of no
further force or effect.
3. Subject to Paragraph 2, Tenaska accepts the Capacity Release of the
Northwest Transportation Agreements and will assume all of Cascade's
rights, obligations, duties and liabilities under the Northwest
Transportation Agreements from and after the Capacity Release Date
including, but not limited to, Cascade's obligation to compensate
Transporter (as specified in the Northwest Transportation Agreements), and
all other rights, duties, liabilities and additional obligations incurred
pursuant to the provisions of the Northwest Transportation Agreements from
and after the Capacity Release Date. The Capacity Release is a release of
all of the right, title and interest of Cascade in, to and under the
Northwest Transportation Agreements and an assumption by Tenaska of all the
rights, obligations, duties and liabilities of Cascade under the Northwest
Transportation Agreements effective as of the Capacity Release Date.
4. Liability for all obligations accruing under the Northwest Transportation
Agreements prior to the Capacity Release Date shall be determined in
accordance with the provisions of the Buy/Sell Agreement or such Capacity
Releases as may be in effect as of the date of execution of this Agreement.
Tenaska hereby indemnifies Cascade against liability for all obligations
accruing under the Northwest Transportation Agreements on and after the
Capacity Release Date.
5. Cascade represents and warrants to Tenaska that the copies of the Northwest
Transportation Agreements appended hereto as Attachment A and Attachment B
are true and correct copies thereof as in effect on the date hereof and
have not been amended, modified or waived and are not subject to any prior
capacity release by Cascade that is
<PAGE>
(6)
operative on or after the Capacity Release Date and that, to the best of
Cascade's knowledge, no event has occurred as of the date hereof which,
with or without the passage of time or the giving of notice, or both, would
constitute a default on the part of Cascade thereunder.
6. From the date of execution of this Agreement until the Capacity Release
Date, Cascade agrees to hereafter operate and manage the Northwest
Transportation Agreements and activities associated therewith in accordance
with, with due regard to, and so as not to impair, Tenaska's rights under
this Agreement. Cascade will not amend, exercise elections or options or
otherwise alter the Northwest Transportation Agreements in any manner which
would affect either Party's rights or obligations under this Agreement
without Tenaska's prior written consent, which consent shall not be
unreasonably withheld. Cascade covenants and agrees not to hereafter
release all or any part of the Northwest Transportation Agreements to any
third party if such release were to impede Cascade's obligations or
Tenaska's rights under this Agreement. At the request of Tenaska, and at
Tenaska's expense, Cascade shall endeavour to secure from Northwest, any
amendments, elections, options or other alterations to the Northwest
Transportation Agreements as are reasonably requested by Tenaska from time
to time and the realization of which would not be detrimental to Cascade's
commercial interests.
7. Any notice under this Agreement shall be in writing and shall be deemed
given on the earlier of (i) the date received by the addressee when
delivered by hand, or (ii) the day following the date sent by
telecommunications means to the numbers set forth below, or (iii) five (5)
days after mailing by prepaid registered United States mail, directed to
the post office address of the parties as follows (provided that, at any
time when there is a strike affecting delivery of either United States
mail, all such deliveries shall be made by hand or by telecommunications):
<PAGE>
(7)
If to Cascade: Cascade Natural Gas Corporation
222 Fairview Avenue North
Seattle, Washington, U.S.A. 98109
Attention: Vice President, Gas Supply
Telecopy: 206/624-3900
Telephone: 206/624-7215
If to Tenaska: Tenaska Washington Partners, L.P.
407 North 117 Street
Omaha, Nebraska, U.S.A. 68154
Attention: President, Tenaska Washington, I
Telecopy: 402/691-9526
Telephone: 402/691-9500
Tenaska Gas Co.
407 North 117 Street
Omaha, Nebraska, U.S.A. 68154
Attention: President
Telecopy: 402/691-9538
Telephone: 402/691-9500
Any Party may, by like written notice, designate a new address to which
such shall be directed.
8. This Agreement can be waived, modified, amended, terminated or discharged
only explicitly in a writing signed by each of the Parties hereto. A
waiver shall be effective only in a specific instance and for the specific
purpose given. Mere delay or failure to act by a Party hereto shall not
preclude the exercise or enforcement of any of the rights or remedies
hereunder.
9. In the event that any part of this Agreement is determined by any court of
competent jurisdiction to be unenforceable, the balance of this Agreement
shall remain in full force and effect.
<PAGE>
(8)
10. The terms and provisions of this Agreement shall be binding upon and inure
to the benefit of the successors, assigns and legal representatives of the
Parties hereto. Prior to the Capacity Release Date, neither Party may
assign this Agreement or any of its rights or obligations hereunder,
without the prior written consent of the other Party, such consent not to
be unreasonably withheld. Notwithstanding the preceding, Tenaska may
assign, transfer and pledge all or any part of its rights, interests,
claims and benefits herein to any third party for the purposes of providing
security for existing or intended financing of the Facility, and Cascade
hereby consents to the creation of any lien or charge in connection
therewith. In addition, subject to establishing acceptable credit
worthiness to Northwest and the Parties, Cascade and Tenaska shall have the
right to assign this Agreement to a business entity that is affiliated with
Cascade or Tenaska (as the case may be) where such assignment is necessary
for the purpose of enabling Cascade or Tenaska to gain the maximum
commercial advantage available to it in meeting its obligations under this
Agreement.
11. Gas Co. and Partnership shall be jointly and severally liable for the
obligations of Tenaska under this Agreement however, each of Gas Co. and
Partnership shall have the right, upon sixty (60) days written notice, to
terminate this Agreement to Gas Co. only. Following the effective date of
any such termination of this Agreement as to Gas Co., (i) Gas Co. shall
have no further rights, obligations or liabilities under this Agreement,
except with respect to liabilities accruing prior to the effective date of
such termination, and (ii) this Agreement will continue in full force and
effect, without further modification or amendment, as between Cascade and
Partnership.
12. This Agreement shall be construed and enforced in accordance with, and the
rights of the Parties shall be governed by, the laws of the State of
Washington.
<PAGE>
(9)
IN WITNESS WHEREOF, Cascade, Gas Co. and Partnership have caused this Agreement
to be signed in their names by their duly authorized representatives and
delivered as their act and deed, intending to be legally bound by its terms and
provisions.
CASCADE NATURAL GAS CORPORATION Attest:
By: _________________________________ _________________________________
TENASKA GAS CO. Attest:
By: _________________________________ _________________________________
Title: Title:
TENASKA WASHINGTON PARTNERS, L.P.
By: Tenaska Washington I, L.P.,
Managing General Partner
By: Tenaska Washington, Inc.
Managing General Partner Attest:
By: _________________________________ _______________________________
Title: Title:
<PAGE>
EXHIBIT 12
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND PREFERRED DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------------------------
1994 1993 1992 1991 1990
-------- -------- ------- -------- --------
(dollars in thousands)
<S> <C> <C> <C> <C> <C>
Fixed charges, as defined:
Interest expense 8,090 7,038 7,478 7,793 8,374
Amortization of debt issuance expense 593 562 402 362 373
------- ------- ------- -------- --------
Total fixed charges 8,683 7,600 7,880 8,155 8,747
------- ------- ------- -------- --------
Earnings, as defined:
Net earnings 5,760 9,103 4,843 7,651 8,376
Add (deduct):
Income taxes 3,505 5,224 2,817 4,206 4,547
Cumulative effect of change
In accounting method - (209) - - -
Fixed charges 8,683 7,600 7,880 8,155 8,747
------- ------- ------- -------- --------
Total earnings 17,948 21,718 15,540 20,012 21,670
------- ------- ------- -------- --------
Ratio earnings to fixed charges 2.07 2.86 1.97 2.45 2.48
------- ------- ------- -------- --------
------- ------- ------- -------- --------
Fixed charges and preferred
dividend requirements:
Fixed charges 8,683 7,600 7,880 8,155 8,747
Preferred dividend requirements 898 913 941 229 238
------- ------- ------- -------- --------
Total 9,581 8,513 8,821 8,384 8,985
------- ------- ------- -------- --------
Ratio of earnings to fixed charges
and preferred dividend requirements 1.87 2.55 1.76 2.39 2.41
------- ------- ------- -------- --------
------- ------- ------- -------- --------
</TABLE>
<PAGE>
INDEPENDENT AUDITORS' CONSENT
-------------------------------------------------------------------------------
We consent to the incorporation by reference in Registration Statement
No. 33-71286, No. 33-51377, and No. 33-29801 on Forms S-3 and No. 33-39873 on
Form S-8 of Cascade Natural Gas Corporation, of our reports dated February 3,
1995, appearing in this Annual Report on Form 10-K of Cascade Natural Gas
Corporation for the year ended December 31, 1994.
DELOITTE & TOUCHE LLP
Seattle, Washington
March 24, 1995
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 213,929
<OTHER-PROPERTY-AND-INVEST> 3,834
<TOTAL-CURRENT-ASSETS> 42,524
<TOTAL-DEFERRED-CHARGES> 12,010
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 272,297
<COMMON> 8,912
<CAPITAL-SURPLUS-PAID-IN> 67,992
<RETAINED-EARNINGS> 10,806
<TOTAL-COMMON-STOCKHOLDERS-EQ> 87,710
7,217
0
<LONG-TERM-DEBT-NET> 100,000
<SHORT-TERM-NOTES> 14,501
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 5,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 57,869
<TOT-CAPITALIZATION-AND-LIAB> 272,297
<GROSS-OPERATING-REVENUE> 192,410
<INCOME-TAX-EXPENSE> 3,505
<OTHER-OPERATING-EXPENSES> 174,581
<TOTAL-OPERATING-EXPENSES> 178,086
<OPERATING-INCOME-LOSS> 14,324
<OTHER-INCOME-NET> (84)
<INCOME-BEFORE-INTEREST-EXPEN> 14,240
<TOTAL-INTEREST-EXPENSE> 8,480
<NET-INCOME> 5,760
558
<EARNINGS-AVAILABLE-FOR-COMM> 5,202
<COMMON-STOCK-DIVIDENDS> 8,472<F1>
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 12,851
<EPS-PRIMARY> 0.60
<EPS-DILUTED> 0.60
<FN>
<F1>Amount represents total common stock dividends declared. This amount
differs from the $8,154,000 shown on the Consolidated Statement of Cash Flows,
which is net of reinvested dividends of $876,000, and includes $558,000 of
preferred dividends.
</FN>
</TABLE>
