<Page>
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____ TO _____.
Commission File No. 1-8796
QUESTAR CORPORATION
----------------------------------------------------
(Exact name of registrant as specified in its charter)
State of Utah 87-0407509
- ------------------------------- --------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433
- -------------------------------------------------------- ----------
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (801) 324-5000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange on
Title of each class which registered
------------------- ------------------------
Common Stock, Without Par Value, with New York Stock Exchange
Common Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No/ /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
The aggregate market value of the registrant's common stock, without par
value, held by nonaffiliates on March 1, 2002, was $1,826,924,606 (based on the
closing price of such stock).
On March 1, 2002, 81,620,810 shares of the registrant's common stock,
without par value, were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE. Portions of the definitive Proxy Statement
for the 2002 Annual Meeting of Stockholders are incorporated by reference into
Part III. The sections of the Proxy Statement labelled "Committee Report on
Executive Compensation" and "Cumulative Total Shareholder Return" are expressly
not incorporated into this document.
================================================================================
<Page>
TABLE OF CONTENTS
<Table>
<Caption>
HEADING PAGE
- ------- ----
PART I
Items 1.
and 2. BUSINESS AND PROPERTIES........................................................................ 1
General.................................................................................... 1
Market Resources, General...................................................................3
Market Resources, Exploration and Production .............................................. 3
Market Resources, Gathering, Marketing and Trading......................................... 7
Market Resources, Regulation ...............................................................8
Market Resources, Competition and Customers.................................................9
Regulated Services, Introduction............................................................9
Regulated Services, Retail Distribution....................................................10
Regulated Services, Transmission and Storage...............................................14
Regulated Services, Other Services.........................................................18
Other Operations...........................................................................19
Employees..................................................................................20
Environmental Matters......................................................................20
Research and Development...................................................................20
Oil and Gas Operations ....................................................................20
Item 3. LEGAL PROCEEDINGS..............................................................................23
Item 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS...............................................................................25
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS................................................................25
Item 6. SELECTED FINANCIAL DATA........................................................................26
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATION......................................................................................27
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.....................................39
Item 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.............................................................................42
Item 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE...........................................................................42
</Table>
-i-
<Page>
<Table>
<Caption>
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANT..............................................................................42
Item 11. EXECUTIVE COMPENSATION.........................................................................43
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT..........................................................................44
Item 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS...................................................................................44
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K........................................................................44
SIGNATURES..................................................................................................86
</Table>
-ii-
<Page>
FORM 10-K
ANNUAL REPORT, 2001
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES.
GENERAL
Registrant Questar Corporation ("Questar" or "the Company") is a
diversified energy services holding company that is involved in the full
spectrum of natural gas activities through two divisions-Market Resources and
Regulated Services. Market Resources engages in energy development and
production; gas gathering and processing; and wholesale gas and hydrocarbon
liquids marketing, risk management, and storage. Regulated Services, through two
subsidiaries, conducts interstate gas transmission and storage activities and
retail gas distribution services. The Company is also involved in providing
integrated information and communication services.
Questar was organized in 1984 and became a publicly held entity when the
shareholders of Questar Gas Company ("Questar Gas," then known as Mountain Fuel
Supply Company) approved a corporate reorganization. Questar was created to
provide organizational and financial flexibility and to achieve a more clearly
defined separation of utility and nonutility activities. Questar is a "holding
company," as that term is defined in the Public Utility Holding Company Act of
1935, because Questar Gas is a natural gas utility. The Company, however,
qualifies for and claims an exemption from provisions of such act applicable to
registered holding companies.
As is noted in the following chart, Questar's Market Resources unit
includes a subholding company, Questar Market Resources, Inc. ("QMR"), which
owns Wexpro Company ("Wexpro"), Questar Exploration and Production Company
("Questar E&P") and its Canadian affiliate, Celsius Energy Resources Ltd.
("Celsius"), Shenandoah Energy Inc. ("SEI"), Questar Gas Management Company
("QGM"), and Questar Energy Trading Company ("QET"). Questar's Regulated
Services unit also includes a subholding entity--Questar Regulated Services
Company ("QRS")--in addition to Questar Gas, Questar Pipeline Company ("Questar
Pipeline") and Questar Energy Services, Inc. ("QES").
The Company's information and communication activities are conducted by
Questar InfoComm, Inc. ("Questar InfoComm") which, in turn, currently owns
approximately 89 percent of Consonus, Inc. ("Consonus").
<Page>
<Table>
QUESTAR
CORPORATION
|
---------------------------------|----------------------------------
| | |
Questar Questar Questar
InfoComm, Inc. Market Regulated
(Information and Resources, Services
Communication Inc. Company
Services) (Subholding (Subholding
| Company) Company)
| | |
| | ----------------------|---------------------
| | | | |
Consonus, Inc. | Questar Gas Questar Questar
(Networking, | Company Pipeline Energy
Website and Data Se- | (Retail Company Services
curity Services) | Distribution) (Transportation Inc.
| | and Storage (Nonregulated
| | Products &
| | Services
|
----------------------------------------------------------------------------
| | | |
Wexpro Questar Exploration and Questar Energy Questar Gas
Company Production Company, Trading Com- Management
(Management and Shenandoah Energy any Company
Development, Inc., and Celsius Energy (Wholesale Mar- (Gathering and
Cost-of-Service Resources, Ltd. keting, Trading, Processing
Properties) (Exploration and Production) Risk Management,
Storage)
</Table>
As a diversified provider of energy services, Questar believes that its
structure enhances its operating flexibility to take advantage of the earnings
growth potential of exploration and production operations, wholesale marketing,
gathering and processing even as it continues to take advantage of opportunities
to expand its regulated activities through customer additions, new pipeline
projects, and expanding hub services. Questar's management is convinced that
experience in the various activities along the natural gas value
chain--production, gathering, processing, transportation, storage,
distribution--enable the Company to develop and implement strategies for taking
advantage of opportunities associated with the expected demand for natural gas
and for services relating to the effective use of natural gas. Questar, however,
is also concerned about the increased risks associated with traditional utility
operations as regulators and politicians fail to understand the need for
competitive returns and to reward efficient operators.
Questar intends to continue emphasizing the ownership of assets--reserves,
pipelines, storage reservoirs, distribution systems--as it fulfills stated
objectives to enter new markets, provide new services, and take advantage of the
convergence of natural gas and electricity. The Company has important joint
venture arrangements and will continue to pursue new alliances to strengthen its
position and exploit its assets.
-2-
<Page>
Financial information concerning the Company's lines of business, including
information relating to the amount of total revenues contributed by any class of
similar products or services responsible for 10 percent or more of consolidated
revenues, is presented in Note 12 of the Notes to Consolidated Financial
Statements under Item 14.
The Company's activities are discussed below.
MARKET RESOURCES, GENERAL.
The Market Resources unit is the primary growth area within the Company.
Over the next five years, Questar expects to spend approximately 60-70 percent
of its total capital budget in Market Resources, primarily to expand oil and gas
reserves through drilling and acquisitions; enlarge an infrastructure of
gathering systems, processing plants, header facilities, and storage facilities;
and continue risk management and electric power generation activities. The
diversity of activities within the group enhances a basic strategy to pursue
complementary growth. As Questar E&P, SEI and Celsius (QMR's exploration and
production subsidiaries), for example, find and acquire new reserves, QGM will
have opportunities to expand gathering and processing activities, and QET will
have more physical production to support its marketing and storage programs.
MARKET RESOURCES, EXPLORATION AND PRODUCTION
The Company has been in the exploration and production ("E&P") business
since its organization in 1935. Through the ensuing years, the Company's E&P
activities have generated substantial economic benefits for the Company and its
shareholders and customers and have expanded in size and geographic location.
The year 2001 was the third consecutive banner year for the Company's E&P
operations as it expanded both reserves and production when it purchased SEI.
Effective July 31, 2001, QMR purchased SEI, a privately-held entity engaged
in production, gathering, processing and drilling activities, for $403 million
including cash and assumed debt. The acquisition involved 415 billion cubic feet
equivalent ("Bcfe") of proved reserves (72 percent natural gas and 28 percent
oil), 114,000 net acres of undeveloped leasehold acreage, 100 million cubic feet
("MMcf") per day of natural gas processing capacity, 90 miles of gathering
lines, and four drilling rigs. These assets constitute the largest acquisition
in Questar's history and are located in the Company's core operating area that
already includes extensive pipeline and gathering systems.
Questar's E&P group includes Questar E&P and Celsius in addition to SEI.
These entities form a unique E&P group that conducts a blended program of
low-cost development drilling and low-risk reserve acquisition. Questar's E&P
group has a large inventory of proved undeveloped properties that should be
converted into production over the next several years. It will also continue to
identify promising exploration prospects and farm them out to entities that are
willing to assume the initial drilling risks, while retaining some ownership
percentage.
The E&P group also maintains a geographical balance and diversity, while
focusing its activities in core areas where it has accumulated geological
knowledge and has significant expertise. Core areas of activity are the Rocky
Mountain region of Wyoming, including the Uinta Basin of eastern Utah and the
Pinedale Anticline area of western Wyoming; the Midcontinent region of
-3-
<Page>
Oklahoma, the Texas Panhandle, East Texas, and the Upper Gulf Coast; the
Southwest region of northwestern New Mexico and southwestern Colorado; and the
Western Canadian Sedimentary Basin located primarily in Alberta, Canada.
Natural gas remains the primary focus of the Company's E&P operations. As
of year-end 2001, the Company had proved reserves (excluding Questar Gas's
cost-of-service reserves) of 998.0 Bcf of gas and 31.1 million barrels
("MMBbls") of oil and natural gas liquids, compared to 639.9 Bcf of gas and 15.0
MMBbls of oil as of the same date in 2000. (Any references to oil in this report
include natural gas liquids.) On an energy-equivalent ratio of six thousand
cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil, natural
gas comprised approximately 84.3 percent of proved reserves (excluding
cost-of-service reserves). Proved developed gas reserves constituted 58.9
percent of the total non-regulated proved gas reserves reported. Approximately
6.2 percent of the group's proved natural gas reserves and 10.7 percent of its
proved oil reserves are located in Canada. SEE "Oil and Gas Operations," a
separate section of this report, for additional information concerning the
Company's oil and gas activities on a consolidated basis.
The E&P group's drilling activities occurred in four core operating areas:
Midcontinent and Upper Gulf Coast; Rocky Mountains, including the Uinta Basin in
eastern Utah; Pinedale Anticline in western Wyoming (separated out from the
Rocky Mountain area given its key importance); and western Canada. During 2001,
the E&P companies and Wexpro, on a combined basis, participated in 337 gross
wells (130.3 net), compared to 316 gross wells (94 net) in 2000. The 337 wells
included 247 gas wells, 16 oil wells, 18 dry holes and 56 wells in progress
(waiting on completion or drilling) at year-end. The overall drilling success
(on a net well count basis) in 2001 was 95 percent, compared to 90 percent in
2000.
QMR's Pinedale activities in 2001 continue to merit special emphasis. As of
year-end 2001, Questar E&P and Wexpro reported 30 producing wells and five
awaiting completion or drilling. Drilling results and initial production tests
confirmed reserve expectations of 4.8 to 5.75 Bcfe per well, depending on
location. As of December 31, 2001, the gross daily production from the 30 QMR
wells in Pinedale was estimated at 63 MMcf, compared to 26 MMcf as of the period
a year earlier.
Questar E&P and Wexpro expect to continue drilling activities in Pinedale
when government restrictions permit. On a combined basis, they have an
approximate 60 percent average working interest in 14,800 acres in the Mesa Area
of the Pinedale Anticline. The original Pinedale drilling program projected 135
to 150 locations, based on 80-acre spacing. Questar E&P and Wexpro continue to
assess the feasibility of using 40-acre spacing, which would double the number
of wells.
QMR's activities in Pinedale illustrate its long-term approach. Wexpro held
the leasehold acreage by production as a result of three wells drilled in the
area during the mid-1970's. Pinedale gas reserves are contained in tight sands
with a low porosity. Consequently, Questar E&P and Wexpro did not drill
additional wells in the area until other companies developed new stimulation
techniques that fractured sandstone formations at multiple intervals and
successfully used such techniques to drill wells in neighboring fields. The
Pinedale wells are expensive to drill; future wells drilled to 13,000 feet
levels will cost between $2.6 and $3.6 million. This cost reflects the
completion depth of the wells, the need for special handling and multiple
stimulations, and
-4-
<Page>
governmental orders that impose surface-use limitations and preclude drilling
activities during specified periods.
QMR also plans to aggressively develop the SEI acreage in the Uinta Basin
of eastern Utah, particularly the large inventory of low-risk tight-sand
development locations in the Wasatch Formation. This formation lies beneath the
Green River Formation, which the E&P group believes may contain significant
volumes of unrecovered oil. Wasatch development drilling will allow QMR to
evaluate the remaining potential of the Green River.
The Questar E&P group's gas production increased from 69.0 Bcf in 2000 to
70.6 Bcf in 2001. The increase in production was attributable to reserve
acquisitions and expanded development activities, which more than offset the
natural decline in some producing areas and the sale of producing reserves. The
E&P companies received an average selling price of $3.21 per Mcf in 2001,
compared to $2.80 per Mcf in 2000. Gas production is produced from four separate
regions--the Midcontinent area, San Juan Basin area, Rocky Mountain area, which
includes both the Pinedale Anticline area and the Uinta Basin area, and western
Canada area. Production from each of these areas is generally priced below the
Henry Hub pricing center in Louisiana, reflecting demand and access to
transportation.
Natural gas prices continued to be volatile during 2001, with spot prices
for Rocky Mountain production ranging from a high in excess of $6.00 per Mcf in
the first quarter to a low of below $1.00 per Mcf in the third quarter of 2001.
The E&P group hedges as much as 50-75 percent of its natural gas production in
order to minimize the effect of price volatility on revenues and to lock in
prices that will enable it to meet strategic objectives. (SEE Item 7 and Notes 1
and 6 of the Notes to Consolidated Financial Statements in Item 14.) Hedging
activities are conducted by QET.
During 2001, the E&P companies produced 2.5 MMBbls of oil, compared to 2.2
MMBbls in 2000. The production was sold at an average price of $19.22 per barrel
in 2001, compared to $20.80 per barrel in 2000.
The E&P group continued to generate Section 29 tax credits during 2001.
These tax credits are available for production from wells that meet specified
criteria, including a requirement that drilling of the wells was commenced prior
to January 1, 1993. Properties are often referred to as "tight sands," "coal
seams," or low permeability formations from which it is generally more expensive
to produce gas. During 2001, Questar E&P recorded $5.0 million in Section 29
credits, compared to $4.7 million in 2000. Under current law, 2002 will be the
last year in which Section 29 tax credits are available.
The production of oil and gas is subject to regulation by appropriate
federal and state agencies in the United States and by federal and provincial
agencies in Canada. In general, these regulatory agencies are authorized to make
and enforce regulations to prevent waste of oil and gas, protect the correlative
rights and opportunities to produce oil and gas by owners of a common reservoir,
and protect the environment. Many leases held or operated by the E&P group are
federal or Crown (Canadian) leases subject to additional regulatory
requirements. As illustrated by the actions taken by the Bureau of Land
Management for Pinedale, agencies are generally imposing
-5-
<Page>
more restrictions on access to leasehold acreage, thereby increasing the
planning time to obtain drilling permits and limiting the E&P group's
flexibility to adapt quickly to new developments.
The Questar E&P group maintains regional offices in Denver, Colorado;
Tulsa, Oklahoma; and Oklahoma City, Oklahoma. Canadian operations are managed
through an office in Calgary, Alberta.
WEXPRO COMPANY. Wexpro was incorporated in 1976 as a subsidiary of Questar
Gas. Questar Gas's efforts to transfer producing properties and leasehold
acreage to Wexpro resulted in protracted regulatory proceedings and legal
adjudications that ended with a court-approved settlement agreement that was
effective August 1, 1981.
Wexpro, unlike the members of the E&P group, does not conduct exploratory
operations and does not acquire leasehold acreage for exploration activities. It
conducts oil and gas development and production activities on certain producing
properties located in the Rocky Mountain region under the terms of the
settlement agreement. (The terms of the settlement agreement are described in
Note 11 of the Notes to Consolidated Financial Statements under Item 14.) Wexpro
produces gas from specified properties for Questar Gas and is reimbursed for its
costs plus a return on its investment. In connection with its operations, Wexpro
charges Questar Gas for its costs plus a specified rate of return, which
averaged 19.7 percent on an after-tax basis in 2001 and is adjusted annually
based on a specified formula on its net investment in such properties adjusted
for working capital and deferred taxes. At year-end 2001, Wexpro's investment
(net of deferred income taxes) in cost-of-service operations was $161.3 million
compared to $124.8 million at year-end 2000. Under the terms of the settlement
agreement, Wexpro bears all dry hole costs. The settlement agreement is
monitored by the Utah Division of Public Utilities, the staff of the Public
Service Commission of Wyoming and experts retained by these agencies.
The gas volumes produced by Wexpro for Questar Gas are reflected in the
latter's rates at cost-of-service prices. Cost-of-service gas (defined to
include the gas attributable to royalty interest owners) produced by Wexpro
satisfied 44 percent of Questar Gas's system requirements during 2001. Questar
Gas relies upon Wexpro's drilling program to develop the properties from which
the cost-of-service gas is produced. During 2001, the average wellhead cost of
Questar Gas's cost-of-service gas was $2.55 per decatherm ("Dth"), which was
lower than Questar Gas's average price for field-purchased gas.
Wexpro participates in drilling activities in response to the demands of
other working interest owners, to protect its rights, and to meet the needs of
Questar Gas. Wexpro, in 2001, produced 41.0 Bcfe of natural gas and hydrocarbon
liquids from Questar Gas's cost-of-service properties and added reserves of 69.1
Bcfe through drilling activities and reserve estimate revisions. (These numbers
do not include the related royalty gas.)
Wexpro, under the terms of the Wexpro agreement, owns oil-producing
properties. The revenues from the sale of crude oil produced from such
properties are used to recover operating expenses and provide Wexpro with a
return on its investment. In addition, Wexpro receives 46 percent of any
residual income. (The remaining income is received by Questar Gas and is used to
reduce natural gas costs reflected in customer rates.)
-6-
<Page>
Wexpro has an ownership interest in the wells and facilities related to its
oil properties and in the wells and facilities that have been installed to
develop and produce gas properties described above since August 1, 1981 (a date
specified by the settlement agreement referred to above). Wexpro maintains an
office in Rock Springs, Wyoming, in addition to its principal office in Salt
Lake City, Utah.
MARKET RESOURCES, GATHERING, MARKETING AND TRADING
QGM conducts gathering and processing activities in the Rocky Mountain and
Midcontinent areas. Its activities are not subject to regulation by the Federal
Energy Regulatory Commission (the "FERC") because the Natural Gas Act of 1938
specifically provides that the FERC's jurisdiction does not extend to facilities
involved in the production or gathering of natural gas.
During 2001, QGM changed the scope of its operations when it and Western
Gas Resources ("Western Gas") formed a new joint venture--Rendezvous Gas
Services ("Rendezvous")--to develop and operate new gathering and compression
facilities in the Hoback Basin of southwestern Wyoming. The Hoback Basin
includes the Pinedale Anticline area in which Questar E&P and Wexpro have
developed reserves as well as producing areas south of Pinedale. Gas reserves
from more than 179,000 gross acres are dedicated to Rendezvous under existing
gathering contracts. Rendezvous plans to deliver gas volumes from this area for
processing and blending to the Blacks Fork plant in which QGM has a 50 percent
interest and to the Granger plant owned by an affiliate of Western Gas.
The year also witnessed a functional combination of QGM's gathering
facilities in eastern Utah with SEI's gathering assets. As previously mentioned,
SEI's eastern Utah assets include 90 miles of gas gathering lines and the Red
Wash processing plant that has a daily processing capacity of 100 MMcf.
QGM's gathering system was originally built as part of a regulated
enterprise. It consists of 1,385 miles of gathering lines, compressor stations,
field dehydration plants and measuring stations and was largely built to gather
production from Questar Gas's cost-of-service properties. Under a contract that
was assigned when the gathering assets were transferred from Questar Pipeline,
QGM is obligated to gather the cost-of-service production for the life of the
properties. During 2001, QGM gathered 37.2 million decatherms ("MMDth") of
natural gas for Questar Gas, compared to 36.8 MMDth in 2000.
QGM also gathers gas for affiliates within QMR and for nonaffiliated
customers. During 2001, QGM gathered 27.0 MMDth for QMR affiliates, compared to
25.0 MMDth in 2000, and gathered 91.7 MMDth for nonaffiliated customers,
compared to 93.0 MMDth in 2000.
QGM continues to own a 50 percent interest in the Blacks Fork processing
plant, which has a daily capacity of 84 MMcf and could be expanded to handle
additional volumes gathered by Rendezvous. A processing plant strips liquids
such as butane and ethane from natural gas volumes to enable the producers to
meet pipeline specifications for their gas volumes and to capitalize on
historical price advantages for natural gas liquids when compared to natural gas
volumes. QGM and Wexpro jointly own a processing facility located in the Canyon
Creek area of southwestern
-7-
<Page>
Wyoming that has an operating capacity of 43 MMcf per day. QGM also owns
interests in other processing plants in the Rocky Mountain and Midcontinent
areas.
QET conducts energy marketing activities. It combines gas volumes purchased
from third parties and equity production (production that is owned by
affiliates) to build a flexible and reliable portfolio. QET aggregates supplies
of natural gas for delivery to large customers, including industrial users,
municipalities, and other marketing entities. During 2001, QET marketed a total
of 91.8 equivalent MMDth ("EMMdth") of natural gas and earned a margin of $.149
per equivalent Dth. (The volumes and margins exclude affiliated production.)
QET uses derivatives as a risk management tool to provide price protection
for physical transactions involving equity production and marketing
transactions. It executed hedges for equity production on behalf of the Questar
E&P group with a variety of contracts for different periods of time. QET does
not engage in speculative hedging transactions. (SEE Notes 1 and 6 of the Notes
to Consolidated Financial Statements included in Item 14 of this report for
additional information relating to hedging activities.)
As a wholesale marketing entity, QET concentrates on markets in the Pacific
Northwest, Rocky Mountains, Midwest, and western Canada that are close to
reserves owned by affiliates or accessible by major pipelines. It has contracted
for firm-transportation capacity on pipelines and firm-storage capacity at Clay
Basin.
QET, through a limited liability company in which it has a 75 percent
interest, operates the Clear Creek storage facility located in southwestern
Wyoming. This facility has 8 Bcf of capacity and is connected with lines owned
by Questar Pipeline, The Williams Companies, and Overthrust Pipeline Company. A
pipeline connection with the Kern River line is planned for 2002.
QET is also responsible for reviewing possible electric power projects that
will allow the Company to add electric power generation to its natural gas value
chain. QET's strategy involves reviewing power generation opportunities in
western states that are complementary to the Company's pipeline, gas storage and
production assets. It will only invest in power projects that are supported by
long-term purchase agreements with counterparties that have good credit.
Finally, this entity is involved in the final stages of negotiating an alliance
with a major energy marketing company. The first phase of the project involves
QET's contracted capacity at Questar Pipeline's Clay Basin storage project.
MARKET RESOURCES, REGULATION
QMR's operations are subject to various levels of government controls and
regulation in the United States and Canada at the federal, state/provincial, and
local levels. Such regulation includes requiring permits for the drilling of
wells; maintaining bonding requirements in order to drill or operate wells;
submitting and implementing spill prevention plans; filing notices relating to
the presence, use and release of specified contaminants incidental to oil and
gas regulations; and regulating the location of wells, the method of drilling
and casing wells, surface usage and restoration of properties upon which wells
have been drilled, the plugging and abandoning of wells and the transportation
of production. QMR's operations are also subject to various conservation
-8-
<Page>
matters, including the regulation of the size of drilling and spacing units or
proration units, the number of wells that may be drilled in a unit, and the
unitization or polling of oil and gas properties. State conservation laws
establish the maximum rates of production from oil and gas wells, generally
prohibit the venting or flaring of gas and impose requirements for the ratable
purchase of production.
Some of QMR's leases, including many of its leases in the Rocky Mountain
area, are granted by the federal government and administered by federal
agencies. These leases require compliance with detailed regulations on such
things as drilling and operations on the leases and the calculation and payment
of royalties.
Various federal, state and local environmental laws and regulations affect
the Company's operations and costs. These laws and regulations concern the
generation, storage, transportation, disposal or discharge of contaminants into
the environment and the general protection of public health, natural resources,
wildlife, and the environment. They also impose substantial liabilities for any
failure on the part of the Company to comply with them.
Each province in Canada and the federal government of Canada also have laws
and regulations governing land tenure, royalties, production rates and taxes,
and environmental protection.
MARKET RESOURCES, COMPETITION AND CUSTOMERS
QMR faces competition in all aspects of its business including the
acquisition of reserves and leases; obtaining goods, services, and labor; and
marketing its production. Its competitors include multinational energy companies
and other independent producers, many of which have greater financial resources
than QMR.
QMR's business activities can be subject to seasonal variations.
Historically, the demand for natural gas decreases during the summer months and
increases during the winter months. The increasing demand for natural gas to
generate electricity may cause increased demand during the hottest months of the
summer. Weather (both in terms of temperatures and moisture) can have dramatic
impacts on natural gas prices and QMR's operations.
The Questar E&P group sells its natural gas production to a variety of
customers including pipelines, gas marketing firms, industrial users, and local
distribution companies. QMR's crude volumes are sold to refiners, remarketers
and other companies, some of which have pipeline facilities near the producing
properties. In the event pipeline facilities are not available, crude oil is
trucked to storage, refining, or pipeline facilities.
REGULATED SERVICES, INTRODUCTION
Questar's Regulated Services segment includes Questar Gas, a retail
distribution utility; Questar Pipeline, an interstate pipeline; QES, an entity
engaged in retail energy services, particularly appliance financing and energy
management services; and QRS, a subholding company that is the direct parent of
such entities and provides administrative services to them. All members of the
Regulated Services group have common officers and share service functions, e.g.,
marketing,
-9-
<Page>
planning, business development, engineering, legal, regulatory affairs,
accounting, and budgeting. All Regulated Services employees share base and
incentive compensation programs and are expected to work together to improve
customer service and operating efficiency. The integration of the entities has
resulted in lower operating and maintenance costs and better coordination of
activities and projects.
REGULATED SERVICES, RETAIL DISTRIBUTION
CUSTOMERS AND DELIVERIES. Questar Gas distributes natural gas as a public
utility in Utah and southwestern Wyoming. As of December 31, 2001, it was
serving 731,900 sales and transportation customers, a 3.9 percent increase from
the 704,629 customers as of year-end 2000. (Customers are defined in terms of
active meters.)
Over 96 percent of Questar Gas's customers live in Utah. Questar Gas
distributes gas to customers in the major populated areas of Utah, commonly
referred to as the Wasatch Front in which the Salt Lake metropolitan area,
Provo, Ogden, and Logan are located. It also serves customers in eastern,
central, and southwestern Utah with Price, Roosevelt, Fillmore, Richfield, Cedar
City, and St. George as the primary cities. Questar Gas supplies natural gas in
the southwestern Wyoming communities of Rock Springs, Green River, and Evanston,
and the southeastern Idaho community of Preston. With the mid-2001 acquisition
and merger of Utah Gas Service Company ("Utah Gas"), Questar Gas became the only
gas distribution public utility in Utah and added customers in the cities of
Vernal, Moab, and Monticello, which are all located in eastern Utah. The
concurrent acquisition and merger of Wyoming Industrial Gas Company ("Wyoming
Industrial") added the Wyoming communities of Kemmerer and Diamondville.
Questar Gas added 27,271 customers in 2001, compared to 18,312 new
customers added in 2000. These customer additions include 10,500 customers from
Utah Gas and Wyoming Industrial. Utah's population is still growing faster than
the national average, although the rate of increase is slowing down.
Questar Gas has the necessary regulatory approvals granted by the Public
Service Commission of Utah ("PSCU"), Public Service Commission of Wyoming
("PSCW"), and the Public Utilities Commission of Idaho ("PUCI") to serve these
areas. It also has long-term franchises granted by communities and counties
within its service area.
Questar Gas's sales to residential and commercial customers are seasonal,
with a substantial portion of such sales made during the heating season. The
typical residential customer in Utah (defined as a customer using 115 Dth per
year) consumes over 75 percent of his total gas requirements in the coldest six
months of the year. Questar Gas's revenue forecasts used to set rates are based
on normal temperatures. As measured in degree days, temperatures in Questar
Gas's service area were 2 percent warmer than normal in 2001, which was the
eighth consecutive year in which temperatures have been warmer than normal.
Questar Gas's sensitivity to weather and temperature conditions, however,
has been ameliorated by a weather normalization mechanism for its general
service customers in Utah and Wyoming. The mechanism, which has been in effect
since 1997, adjusts the non-gas portion of a
-10-
<Page>
customer's monthly bill as the actual degree days in the billing cycle are
warmer or colder than normal. This mechanism reduces the sometimes dramatic
fluctuations in any given customer's monthly bill from year to year.
During 2001, Questar Gas sold 83.7 MMDth to residential and commercial
customers, compared to 83.4 MMDth in 2000. General service sales to residential
and commercial customers were responsible for 87.8 percent of Questar Gas's
total revenues in 2001. The increase in sales volumes reflects colder weather
and increased customers. Customers are continuing to decrease their usage on a
temperature-adjusted basis as they use more efficient gas-burning appliances and
respond to higher commodity prices with conservation measures.
Questar Gas has designed its distribution system and annual gas supply plan
to handle design-day demand requirements. It periodically updates its design-day
demand, which is the volume of gas that firm customers could use during
extremely cold weather. For the 2001-02 heating season, Questar Gas used a
design-day demand of 1.036 Bcf for firm sales customers. Questar Gas is also
obligated to have pipeline capacity, but not gas supply, for firm-transportation
customers. Questar Gas's management believes that the distribution system is
adequate to meet the demands of its firm customers.
Questar Gas has been providing transportation service since 1986. It has
worked diligently to retain its transportation customers with cost-based rates.
Transportation service is attractive to customers that can buy volumes of gas
directly from producers and have such volumes transported at aggregate prices
lower than Questar Gas's sales rates.
Questar Gas's largest transportation customers, as measured by revenue
contributions in 2001, are the Gadsby plant operated by Scottish Power
(electric utility) in Salt Lake City; the Kennecott copper processing
operations, located in Salt Lake County; and the mineral extraction
operations of Magnesium Corporation of America in Tooele County, west of Salt
Lake City. Questar Gas's total industrial deliveries, including both sales
and transportation, were basically flat for the two years (65.3 MMDth in 2001
compared to 65.3 MMDth in 2000).
GAS SUPPLY. Questar Gas's competitive position has been strengthened as a
result of owning natural gas producing properties. During 2001, it satisfied 44
percent of its system requirements with the cost-of-service gas produced from
such properties. These properties are operated by Wexpro, and the gas produced
from such properties is transported by Questar Pipeline. Questar Gas's
investment in these properties is included in its utility rate base.
Questar Gas had estimated reserves of 427.8 Bcfe as of year-end 2001,
compared to 399.7 Bcfe as of year-end 2000. (The reserve numbers do not include
volumes attributable to royalty interests, but they do include oil reserves.)
The average wellhead cost associated with Questar Gas's cost-of-service reserves
was below the cost of field-purchased gas. During 2001, Questar Gas recorded
$1.8 million in Section 29 tax credits associated with production from wells on
its cost-of-service properties that qualify for such credits. Questar Gas
believes that it is important to continue owning gas reserves, producing them in
a manner that will serve the best interests of its customers, and satisfying a
significant portion of its supply requirements with gas produced from such
properties.
-11-
<Page>
Questar Gas uses storage capacity at Clay Basin (a base-load storage
facility owned and operated by Questar Pipeline) to provide flexibility for
handling gas volumes produced from cost-of-service properties. It stores gas at
Clay Basin during the summer and withdraws it during the heating season.
Questar Gas has a balanced and diversified portfolio of gas supply
contracts with suppliers located in the Rocky Mountain states of Wyoming,
Colorado, and Utah. During 2001, Questar Gas received regulatory recognition
that price stability, reliability, and cost are the three key factors to
consider when obtaining gas supplies and that costs associated with hedging
activities can be included in its balancing account for pass-through treatment.
When filing its most recent pass-through application with the PSCU, Questar Gas
reported using a blend of fixed-price contracts, price-indexed contracts, and
price-capped contracts as well as spot purchases to fulfill its purchased-gas
supply requirements. In this same application, Questar Gas estimated that its
average cost of purchased gas for 2002 would be $2.94 per Dth for gas delivered
to the upstream pipeline, compared to the $6.75 price it was quoting a year
earlier.
COMPETITION. Questar Gas has historically enjoyed a favorable price
comparison with all energy sources used by residential and commercial customers
except coal and occasionally fuel oil. This historic price advantage, together
with the convenience and handling advantages associated with natural gas, has
permitted Questar Gas to retain 90-95 percent of the residential space and water
heating markets in its service area and to distribute more energy, in terms of
Btu content, than any other energy supplier to residential and commercial
markets in Utah. Questar Gas has close to 100 percent of the space heating and
water heating offered in new homes within its service area that are connected to
its system.
Questar Gas is a public utility and currently has no direct competition
from other distributors of natural gas for residential and commercial customers.
(The PSCW approved a "supplier choice" program for Questar Gas's Wyoming
customers in 1998, but no supplier has yet offered to provide service under the
program.) Questar Gas does compete with other energy sources. It continues to
monitor its competitive position, in terms of commodity costs and efficiency of
usage, with other energy sources.
Questar Gas is also interested in Utah's economic development in order to
enhance market growth and is encouraging the use of natural gas in additional
appliances. Its market share for other gas appliances, e.g., ranges and dryers,
has historically been less than 30 percent, which is significantly lower than
its over 90 percent market share for furnaces and water heaters. Questar Gas
continues to focus marketing efforts to develop incremental load in existing
homes and new construction.
Questar Gas believes that it must maintain a competitive price advantage in
order to retain its residential and commercial customers and to build
incremental load by convincing current customers to convert additional
appliances to natural gas. Consequently, Questar Gas follows an annual gas
supply plan that provides for a judicious balance between cost-of-service gas
and purchased gas and that allows it to increase operating efficiency.
-12-
<Page>
The Kern River pipeline, which was built to transport gas from southwestern
Wyoming to Kern County, California, runs through portions of Questar Gas's
service area and provides an alternative delivery source for transportation
customers. As of the date of this report, Questar Gas has lost no industrial
load as a result of the Kern River pipeline. The existence of this interstate
pipeline system has made it possible for Questar Gas to develop a second source
of supply for its central and its southern Utah system and to take delivery of
additional supplies to meet increasing demand.
Questar Gas and other local distribution companies are faced with the
challenges and opportunities posed by the unbundling and restructuring of
traditional utility services, which have been complicated by some adverse
experiences for customers and suppliers in deregulated states. At this point, it
is too soon to predict a timetable for Questar Gas's unbundling of services to
residential and commercial customers. Questar Gas will continue to examine its
costs, take advantage of technological developments, and improve its overall
efficiency in order to take advantage of opportunities in a deregulated
environment.
REGULATION. As a public utility, Questar Gas is subject to the jurisdiction
of the PSCU and PSCW. (Questar Gas's customers in Idaho are served under the
provisions of its Utah tariff. Pursuant to a special contract between the PUCI
and the PSCU, rates for Questar Gas's Idaho customers are regulated by the
PSCU.) Questar Gas's natural gas sales and transportation services are made
under rate schedules approved by the two regulatory commissions. It is
authorized to earn a return on equity of 11 percent in Utah and 11.83 percent in
Wyoming.
Regulatory treatment of processing costs has been an issue of contention
for the past 30 months. Questar Gas, in order to insure customer safety and give
its customers time to adjust the combustion settings in its service area to
handle lower Btu-gas, determined to enhance the Btu of gas volumes by
contracting to have carbon dioxide removed and agreeing to pay the costs
associated with this activity. The PSCU, however, refused to allow Questar Gas
to reflect such costs in its pass-through applications.
During 2001, Questar Gas achieved a victory in its efforts to obtain
recognition of carbon dioxide removal costs as proper costs for pass-through
treatment. The Utah Supreme Court, by an decision dated October 23, 2001,
determined that the PSCU was not precluded from considering Questar Gas's
application for pass-through treatment of such costs according to previously
approved balancing account procedures and remanded the case back to the PSCU for
a decision on the merits of the case. Questar Gas, in its most recent
pass-through application, requested regulatory permission to recover $5.8
million of such costs through its balancing account.
Questar Gas is still involved in another appeal concerning its processing
costs. After the PSCU granted permission for Questar Gas to recover a portion of
such costs on a prospective basis in its 2000 general rate case, a state agency
(the Committee of Consumer Services) filed an appeal from such order. This case
has not been briefed or argued.
Both the PSCU and the PSCW have authorized Questar Gas to use a balancing
account procedure for changes in the cost of natural gas, including supplier
non-gas costs, and to reflect changes on at least a semi-annual basis. During
2001, Questar Gas filed two pass-through
-13-
<Page>
applications with both the Utah and Wyoming commissions to reflect decreased gas
costs in its rates. In the last pass-through applications that became effective
January 1, 2002, Questar Gas was allowed to reflect annualized gas costs of
$321,711,555 in its Utah rates and $13,159,844 in its Wyoming rates. The typical
residential customer in Utah will have an annual bill of $681.02, using rates in
effect as of January 1, 2002, compared to an annual bill of $905.02, using rates
in effect as of January 1, 2001. The PSCW and PSCU have allowed Questar Gas to
reflect the decreased gas costs in rates, subject to refund.
As previously reported, Questar Gas's pass-through application filed with
PSCU also included a request to recover carbon dioxide removal costs for prior
periods. (The PSCW had not contested Questar Gas's inclusion of such costs in
Wyoming filings.) Finally, Questar Gas requested the PSCU to allow it to
include, on a prospective basis, an allowance for the commodity and supplier
non-gas cost portions of its bad debts in its gas balancing account. The PSCU
has set a hearing date of April 4, 2002, to receive an update from Questar Gas
and other parties concerning the issues raised in the application.
Questar Gas is not earning its authorized return on equity and may file a
general rate case in Utah during 2002. Under Utah law, tariff sheets reflecting
a general rate case became effective 240 days after filing if the PSCU doesn't
render a decision concerning the case by such date.
MISCELLANEOUS. Questar Gas owns and operates distribution systems
throughout its Utah, Wyoming and Idaho service areas and has a total of 22,805
miles of street mains, service lines, and interconnecting pipelines. Questar Gas
has consolidated many of its activities in its operations center located in Salt
Lake City, Utah. It also owns operations centers, field offices, and service
center facilities throughout other parts of its service area. The mains and
service lines are constructed pursuant to franchise agreements or rights-of-way.
Questar Gas has fee title to the properties on which its operation and service
centers are constructed.
REGULATED SERVICES, TRANSMISSION AND STORAGE
Questar Pipeline is an interstate pipeline company that transports natural
gas in the Rocky Mountain states of Utah, Wyoming and Colorado and stores gas
volumes in Utah and Wyoming. As a "natural gas company" under the Natural Gas
Act of 1938, Questar Pipeline is subject to regulation by the FERC as to rates
and charges for storage and transportation of gas in interstate commerce,
construction of new facilities, extensions or abandonments of service and
facilities, accounts and records, and depreciation and amortization policies.
Questar Pipeline holds certificates of public convenience and necessity granted
by the FERC for the transportation and underground storage of natural gas in
interstate commerce and for the facilities required to perform such operations.
TRANSMISSION SYSTEM. Questar Pipeline, as an open-access pipeline,
transports gas for affiliated and unaffiliated customers. It also owns and
operates the Clay Basin storage facility, which is a large underground storage
project in northeastern Utah, and other underground storage operations in Utah
and Wyoming. Questar Pipeline has a 90 percent ownership interest in Overthrust
Pipeline Company ("Overthrust") (recently increased from 72 percent) and,
through a subsidiary, a 50 percent ownership interest in TransColorado Gas
Transmission Company ("TransColorado").
-14-
<Page>
Questar Pipeline's transmission system is strategically located in the
Rocky Mountain area near large reserves of natural gas. It is referred to as a
"hub and spoke" system, rather than a "long-line" pipeline, because of its
physical configuration, multiple connections to other major pipeline systems and
access to major producing areas. Questar Pipeline's transmission system connects
with the transmission systems of Colorado Interstate Gas Company ("CIG"), the
middle segment (commonly referred to as the "WIC segment") of the Trailblazer
pipeline system, The Williams Companies, Inc. ("Williams") including Kern River,
and TransColorado. These connections provide access to markets outside Questar
Gas's service area and allow Questar Pipeline to transport gas for nonaffiliated
customers.
Questar Pipeline's transmission system includes 1,840 miles of transmission
lines that interconnect with other pipelines and link producers of natural gas
with Questar Gas's distribution operations in Utah and Wyoming. (The
transmission mileage figure includes lines at storage fields and tap lines used
to serve Questar Gas, but does not include the 700-mile Southern Trails line.)
This system includes two major segments, often referred to as the northern and
southern systems; the northern system segment extends from northwestern Colorado
through southwestern Wyoming into northern Utah, and the southern system segment
extends from western Colorado to Payson in central Utah. The two portions are
linked together and have significant connections with other pipeline systems,
making it a fully integrated system.
Questar Pipeline's largest single transportation customer is Questar Gas.
During 2001, Questar Pipeline transported 110.3 MMDth for Questar Gas, compared
to 108.2 MMDth in 2000. These transportation volumes include cost-of-service gas
produced by Wexpro on properties owned by Questar Gas as well as some volumes
purchased by Questar Gas directly from field producers.
Questar Gas has reserved firm transportation capacity of about 849,000 Dth
per day on an ongoing basis, or about 60 percent of Questar Pipeline's reserved
capacity. (Questar Gas also contracts for additional capacity during the heating
season.) Questar Pipeline's primary transportation agreement with Questar Gas
was recently extended and expires on June 30, 2017. Questar Gas paid reservation
charges of $52.1 million to Questar Pipeline in 2001; these charges include
reservation charges attributable to firm and "no-notice" transportation. Questar
Gas only needs its total reserved capacity during peak-demand situations. When
it is not fully utilizing such capacity, Questar Gas releases it to others,
primarily industrial transportation customers and marketing entities.
Questar Pipeline recovers approximately 95 percent of its transmission cost
of service through demand charges from firm transportation customers. In other
words, these customers pay primarily for access to transportation capacity.
Consequently, Questar Pipeline's throughput volumes do not have a significant
effect on its short-term operating results. Questar Pipeline's transportation
revenues are not significantly impacted by fluctuating demand based on the
vagaries of weather or natural gas prices. Its revenues would vary with
throughput if the FERC changes its basic regulatory scheme of "straight
fixed-variable" rates.
Questar Pipeline's total system throughput increased from 275.2 MMDth in
2000 to 312.8 MMDth in 2001. Questar Pipeline increased the volumes it
transports for nonaffiliated customers from 158.6 MMDth in 2000 to 195.6 MMDth
in 2001.
-15-
<Page>
Questar Pipeline owns and operates a major compressor complex near Rock
Springs, Wyoming, that compresses volumes of gas from the transmission system
for delivery to the WIC segment of the Trailblazer system and to CIG. The
complex has become a major delivery point on Questar Pipeline's system, with
five of its major natural gas lines connected to the system at the complex. In
addition, both of CIG's Wyoming pipelines and the WIC segment are connected to
the complex.
In addition to the transmission system described above, Questar Pipeline
has a 90 percent interest in and is the operating partner of Overthrust, a
general partnership that owns and operates the Overthrust segment of
Trailblazer. Trailblazer, in turn, is a major 800-mile line that transports gas
from producing areas in the Rocky Mountains to the Midwest. The 88-mile
Overthrust segment is the western-most of Trailblazer's three segments.
The Kern River pipeline, which Williams recently agreed to sell, was built
to transport gas from Wyoming to the enhanced oil recovery projects in Kern
County, California. It runs through Utah's Wasatch Front, making it possible for
some large industrial customers to bypass both Questar Gas and Questar Pipeline
by buying transportation service on Kern River. The new connection between Main
Line 104 (SEE "New Projects") and Kern River permits additional opportunities
for producers and marketers to move gas to Kern River. The Kern River line has
diverted some transportation volumes from both Questar Pipeline and Overthrust.
The Kern River line, on the other hand, has also provided Questar Pipeline with
opportunities to make additional connections with outside markets.
Questar Pipeline's 50 percent ownership interest in the TransColorado
pipeline project is subject to a complex lawsuit that is described under "Legal
Proceedings" later in this report. Until this lawsuit is resolved, Questar
Pipeline is effectively precluded from realizing any value by its contractual
claim to sell its interest in TransColorado to its partner, a subsidiary of
Kinder Morgan Inc. (formerly KN Energy), as early as March 31, 2001.
The TransColorado pipeline project, which commenced operations on March 31,
1999, was built to transport natural gas from the Rocky Mountain area that was
traditionally priced lower than other gas supplies, e.g., San Juan Basin, to
California and Midwestern markets through interconnections with major pipeline
systems. The pipeline originates at a point on Questar Pipeline's system 25
miles east of Rangely in northwestern Colorado and extends 292 miles to the
Blanco hub in northwestern New Mexico.
In its three years of operation, TransColorado has incurred significant
losses because gas prices did not reflect basis differentials that encouraged
producers and market aggregators to transport volumes on the line. Questar
Pipeline wrote down its investment in TransColorado at year-end 1999 and has
been recording operating losses in TransColorado since April 1, 2001, pending
the outcome of the litigation and its ability to sell its interest to its
partner.
NEW PROJECTS. In November of 2001, Questar Pipeline completed its Main Line
104 pipeline, which is 77 miles in length and 24 inches in diameter. The line
extends from Price, Utah, near the Ferron area of coalbed methane gas, to
Questar Gas's system at Payson, Utah, and the Kern River
-16-
<Page>
line near Elberta, Utah. Questar Gas has contracted for approximately 22 percent
of the 272,000 Dth of the firm transportation capacity on the new line.
Questar Pipeline, through a subsidiary, has begun converting the 490-mile
eastern segment of the Southern Trails line that runs from the Blanco hub area
in the San Juan Basin to multiple delivery points near the California state
line. The conversion process includes adding four new compressor stations,
installing additional receipt and delivery connections, and building a line to
the TransColorado pipeline. The segment's daily capacity of 80,000 Dth is fully
subscribed under long-term transportation contracts. The line is expected to be
in service by mid-2002.
Regulatory and marketing constraints have prevented Questar Pipeline from
developing the western segment of Southern Trails that runs from the California
border to Long Beach. While continuing to aggressively pursue natural gas
markets on the California portion of Southern Trails, Questar Pipeline is
exploring other options, including sale or alternative uses, for the western
segment.
Questar Pipeline intends to offer specified hub services such as "parking"
and "loaning" effective May 1, 2002. It will install an additional compressor at
Clay Basin to facilitate such services and has to filed the necessary tariff
revisions with the FERC. Questar Pipeline has introduced the concept of hub
services to customers and believes that its central location, connections to
multiple lines, and the accessibility of storage capacity will enable it to
increase the load factor of its lines and increase its revenues by offering such
services.
STORAGE AND PROCESSING. Questar Pipeline's Clay Basin storage facility in
northeastern Utah is the largest underground storage reservoir in the Rocky
Mountains. The facility has a capacity of 117.5 Bcf. Clay Basin has been
operational since 1977 and has been successfully expanded several times. Storage
service is important to parties that need to balance purchases with fluctuating
customer demand, improve service reliability, and avoid imbalance penalties. The
storage capacity at Clay Basin is fully subscribed by customers under long-term
agreements. Questar Gas currently has 13.4 MMDth of working gas capacity at Clay
Basin. Other large customers, in addition to Questar Gas, include Williams;
Puget Sound Energy Company, a utility in the state of Washington; and Duke
Energy Trading and Marketing L.L.C. Questar Pipeline also offers interruptible
storage service at Clay Basin and allows firm storage service customers the
right to transfer their injection and withdrawal rights to other parties.
Questar Pipeline has proposed using a salt formation located near Evanston,
Wyoming, for the first salt-cavern storage project located in the Rocky Mountain
region. Current plans envision four potential caverns, which are formed through
water leeching techniques, that would each contain 2.5 Bcf of working gas and
that could be cycled 10-12 times per year. Questar Pipeline is finishing a well
that will provide additional engineering data and is soliciting customer
support.
Through a subsidiary, Questar Pipeline also owns gathering lines and
processing plant near Price, Utah, that removes carbon dioxide from coalbed
methane gas in order to raise the Btu content of the gas to be safely and
efficiently used for appliances in Questar Gas's service area. This plant began
operations in June of 1999.
-17-
<Page>
REGULATION. Questar Pipeline does not currently plan to file a general rate
case in 2002. It, however, will continue to review its revenues and costs as it
adds new facilities that are not included in its rate base and makes
expenditures to comply with regulatory mandates.
Questar Pipeline and its affiliates in the Regulated Services group have
actively opposed the FERC's efforts to broaden the scope of its regulations that
are currently limited to "marketing affiliates." The FERC issued a Notice of
Proposed Rulemaking ("NOPR") in September of 2001, in which it proposed rules
that would require pipelines to comply with certain "nondiscriminatory"
standards when dealing with energy company affiliates, including local
distribution companies. At the current time, local distribution companies such
as Questar Gas that do not engage in unregulated gas sales are exempt from the
FERC's marketing affiliate regulations. Questar Pipeline believes that the
current exemption should be continued. If adopted, the FERC's proposed rules
would diminish Questar Pipeline's operational efficiencies and increase its
costs because QRS provides administrative, engineering, gas control, technical,
accounting, legal, and regulatory services to both Questar Pipeline and Questar
Gas.
Questar Pipeline is also required to comply with the FERC's Order No. 637
that requires it, among other things, to offer capacity segmentation to its
transportation customers. Given its configuration as a hub and spoke pipeline,
rather than as a long line, Questar Pipeline argued that traditional
segmentation would reduce shippers' flexibility to use their capacity on its
system and would negatively affect its own throughput capacity. The FERC denied
Questar Pipeline's request of a waiver, but acknowledged that segmentation
should be implemented in a fashion that does not negatively impact firm-capacity
customers. Questar Pipeline has until May 15, 2002 to file tariff provisions
that comply with the segmentation portion of Order No. 637 and has filed a
request for rehearing of the FERC's decision denying its petition for a waiver.
MISCELLANEOUS. Questar Pipeline extended its footprint to other parts of
the western United States by participating in the TransColorado pipeline project
and purchasing the Southern Trails line. There are market risks associated with
these projects, as evidenced by Questar Pipeline's decision to writedown its
investment in TransColorado. Questar Pipeline's efforts to complete the Southern
Trails conversion are affected by its ability to obtain market support and by
the local regulatory and political climate in California.
Competition for Questar Pipeline's transportation and storage services has
intensified in recent years. Regulatory changes have significantly increased
customer flexibility and increased the risks associated with new projects.
Questar Pipeline has two key assets that contribute to its continued success. It
has a strategically located and integrated transmission system with
interconnections to major pipeline systems and with access to major producing
areas and markets and it has significant storage capacity with Clay Basin.
Questar Pipeline's announced projects to build a salt cavern storage project and
to obtain regulatory approval to offer hub services capitalize on these assets.
REGULATED SERVICES, OTHER SERVICES
QES was organized in 1996 to pursue opportunities created by the
deregulation of energy markets and was transferred from QMR to QRS effective
January 1, 1999. QES offers a variety of
-18-
<Page>
non-regulated products and services that include gas measurement, automation and
laboratory services, utility installation and infrastructure services, temporary
natural gas-heating equipment sales and rentals, and appliance financing. It
also develops and manages nonregulated energy and utility projects for
commercial, industrial, and municipal customers. During 2001, QES launched a new
business to provide fueling infrastructure for vehicles and stationary equipment
using natural gas and other alternative fuels.
OTHER OPERATIONS
In addition to the two primary segments of Market Resources and Regulated
Services, Questar has "other operations." This group includes Questar InfoComm,
which is a full-service provider of integrated information and communication
services to affiliates and external businesses; Consonus and limited real estate
operations. Equity securities owned by the Company or Questar InfoComm are also
included in this category.
Questar InfoComm provides information and communication services. It
operates a regional microwave system that covers much of Utah and southwestern
Wyoming. This digital system was originally built to satisfy the needs of
Questar's operations, but also carries data for alternative telephone providers
and other external customers. Questar InfoComm installs and maintains
telephone-switching equipment and voice-mail systems. It built and leases a
fiber optic telephone network in parts of Salt Lake City for an alternative
telephone provider. Questar InfoComm has developed and sold proprietary software
to handle electric grid customers in the United Kingdom and Europe.
In 1999, Questar InfoComm launched Consonus (formerly known as Questar
MetroNet Services), which offers managed hosting and operations services and
critical data center support. Consonus owns three ultra-secure Internet data
centers in the Salt Lake metropolitan area and will consider constructing
additional data centers in other metropolitan areas. These centers are designed
to protect critical systems and data from natural or man-made disasters.
Consonus' operations and expansion opportunities have been negatively affected
by the economic recession in the high tech industry.
As of year-end 2001, Questar retained 788,962 shares of its original 7.8
million shares issued by Nextel, an international wireless communication
company. The Company acquired this stock in 1994 when it sold Questar Telecom, a
specialized mobile radio subsidiary, to Nextel.
Questar no longer owns the office building in downtown Salt Lake City that
serves as its headquarters facility. It does have a long-term lease for the
building and has approximately 750 employees in it. Questar, through a
subsidiary, continues to own property close to the building that is currently
used for parking and will continue to review proposals to develop it.
Through an affiliate, Questar also owns 14.5 acres of commercial real
estate in Salt Lake County that was the site of the Wasatch Chemical clean-up
activities and was being utilized by the organizing committee for the Salt Lake
2002 Olympics. SEE Legal Proceedings. Although the Company intends to continue
owning the property to minimize any future problems associated with
environmental compliance, it believes that the property can earn attractive
returns when leased.
-19-
<Page>
EMPLOYEES
As of December 31, 2001, Questar and its affiliates had 2,221 employees
compared to 2,022 employees at year-end 2000. Of this total, 1,321 worked for
the Regulated Services segment, 581 worked for Market Resources entities, and
319 worked for corporate, Questar InfoComm and Consonus. None of these employees
is represented under collective bargaining agreements. Questar has comprehensive
benefit plans for its employees, but some benefit plans vary by business unit.
Employee relations are generally deemed to be satisfactory.
ENVIRONMENTAL MATTERS
Questar and its affiliates are subject to the National Environmental Policy
Act and other federal and state legislation regulating the environmental aspects
of their businesses. During 2001, Questar continued to be involved in actions
involving local and federal environmental enforcement agencies and allegations
of "hazardous waste" problems. SEE Legal Proceedings for a discussion of
penalties assessed by the Wyoming Department of Environmental Quality against
QMR. The Company does not believe that environmental protection provisions will
have any significant effect on its competitive position; it does believe,
however, that such provisions have added and will continue to add to capital
expenditures and operating costs.
Questar is actively promoting the environmental advantages of natural gas
in comparison to other fuels. It has actively participated in various clean air
committees and has promoted the use of natural gas in automobiles. Questar's
management believes that increasing concerns about environmental pollution will
result in an increased demand for natural gas.
RESEARCH AND DEVELOPMENT
Questar Gas has the primary responsibility for the Company's research and
development activities. It has evaluated gas conversion equipment, gas piping,
and engines using natural gas and also evaluated technological developments with
electrical appliances. The total amount spent by Questar on research and
development activities either directly or through contributions is not
significant.
OIL AND GAS OPERATIONS
Oil and gas operations are significant to the business functions and
financial condition of Questar. (All information set forth below relates to the
Company on a consolidated basis.) Certain information concerning the Company's
oil and gas operations is presented in Note 14 of the Notes to Consolidated
Financial Statements included in Item 14 of this report. The Company does not
have any long_term supply contracts with foreign governments or reserves of
equity investees.
RESERVE REPORTS. The following is a reconciliation of reserve quantities
reported in Note 14 of the Notes to Consolidated Financial Statements and
reserve quantities reported to other regulatory agencies:
-20-
<Page>
During 2001, the Company filed estimated reserves as of year-end 2000 on
Form EIA-23 with the Energy Information Administration in the Department of
Energy and will submit a comparable report for 2001. Although Questar used the
same technical and economic assumptions when it filed this report, it was
obligated to report reserves on wells it operates, not on all wells in which it
has an interest, and to include the reserves attributable to other owners in
such wells.
Questar Gas files information using a FERC Form 2 format with the PSCU and
PSCW and lists gas reserves of 451.4 Bcf (working interest) at December 31,
2001, which include reserves attributable to royalty interests. The 405.7 Bcf
(net revenue interest) reported as cost-of-service gas reserves in Note 12
exclude reserves attributable to royalty interests.
Questar Pipeline files a Form 2 (Annual Report) with the FERC. The Form 2
discloses Questar Pipeline's cushion gas of 70.4 Bcf at December 31, 2001. This
gas is not included in the total reserve number.
OIL AND GAS PRODUCTION.(1)
<Table>
<Caption>
2001 2000 1999
---- ---- ----
Natural gas (MMcf) 108,481 110,509 101,602
Oil (Mbbl) 3,015 2,804 2,934
</Table>
(1) Production quantities from all properties, including cost-of-service
properties.
AVERAGE SALES PRICE.(2)
<Table>
<Caption>
2001 2000 1999
---- ---- ----
Natural gas per Mcf $ 3.21 $ 2.80 $ 2.00
Oil per bbl $19.22 $ 20.50 $ 13.92
</Table>
(2) Average sales price is calculated on production excluding
cost-of-service volumes.
AVERAGE PRODUCTION (LIFTING) COST. The average production cost Mcfe
excludes costs and volumes associated with production of cost-of-service
reserves. One barrel of oil equals the energy content of 6 Mcf of gas.
<Table>
<Caption>
2001 2000 1999
---- ---- ----
Production cost per Mcfe $.83 $.70 $.59
</Table>
PRODUCING WELLS AT DECEMBER 31, 2001.
<Table>
<Caption>
GAS OIL
--- ---
Gross wells 4,310 1,166
Net wells 1,867 589
</Table>
-21-
<Page>
The numbers for gross wells include 98 wells with multiple completions.
LEASEHOLD ACREAGE AT DECEMBER 31, 2001. Questar can retain its interest in
undeveloped acreage by either drilling activity that establishes commercial
production or by the payment of delay rentals. A portion of the unproved acreage
may be allowed to lapse prior to the primary terms of the lease. Leasehold
acreage is located in the United States and Canada. Approximately 80 percent of
the domestic unproved acreage consists of federal and state leases that
generally have ten-year terms. The remaining 20 percent is attributable to fee
leases that generally have three- to five-year terms. About 41 percent of the
unproved acreage is scheduled to expire within the next five years if no
drilling or development activity is undertaken. Substantially all the Canadian
unproved acreage is related to Crown or government leases, which provide for
five-year terms.
The following chart lists the Company's consolidated productive and
unproved acreage:
<Table>
<Caption>
PRODUCTIVE UNPROVED
---------- --------
GROSS NET GROSS NET
----- --- ----- ---
United States 2,294,017 756,285 1,968,466 855,309
Canada 274,317 97,454 323,650 124,833
--------- ------- --------- -------
Total 2,568,334 853,739 2,292,116 980,142
</Table>
NET PRODUCTIVE AND DRY WELLS DRILLED.
<Table>
<Caption>
EXPLORATORY WELLS DEVELOPMENT WELLS
----------------- -----------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
Productive 1 122 85 84
Dry 2 3 1 5 6 8
- - - --- -- --
Total 3 3 1 127 91 92
</Table>
PRESENT ACTIVITIES. At year-end 2001, Questar affiliates had a working
interest in 46 gross wells waiting on completion and 10 gross wells being
drilled.
DELIVERY COMMITMENTS. Questar Gas is obligated to deliver natural gas to
approximately 732,000 customers in Utah, Wyoming and Idaho, but future
quantities associated with such service are neither fixed nor determinable.
The E&P group sells a majority of its oil and gas production on the
spot-market or under short-term contracts that provide for price readjustments.
-22-
<Page>
ITEM 3. LEGAL PROCEEDINGS.
There are various legal proceedings pending against the Company and its
affiliates. Management believes that the outcome of these cases will not have a
material adverse effect on the Company's financial position or liquidity.
Significant cases are discussed below.
TRANSCOLORADO. Questar TransColorado, Inc. ("QTC"), a subsidiary of Questar
Pipeline, owns a 50 percent interest in TransColorado, which is the partnership
that built and operates the TransColorado pipeline project. QTC and its partner,
KN TransColorado, Inc. ("KNTC") are involved in a complex lawsuit that is
pending in a state district court in Colorado. At center stage in the lawsuit is
the validity of a contractual right claimed by QTC to put its 50 percent
interest in TransColorado to KNTC during the 12-month period beginning March 31,
2001.
KNTC originally filed the lawsuit in June of 2000 alleging that Questar
Pipeline and its affiliates breached their fiduciary duties to TransColorado and
KNTC by developing a plan to construct and operate a new pipeline (this
project--Mainline 104--is described under the section "Regulated Services,
Transportation and Storage") that would compete with TransColorado, rendering it
economically unviable. KNTC is seeking at least $150 million plus punitive
damages, a declaratory judgment that KNTC's obligation to purchase QTC's
interest in the project be declared void and unenforceable, and a dissolution of
the partnership under Colorado law.
QTC and its affiliates subsequently filed a counterclaim against KNTC and
its named affiliates, including Kinder Morgan, Inc., seeking a declaratory
judgment that its contractual right to exercise the put is binding and
enforceable and damages of at least $185 million.
The parties have entered into a stipulation and standstill agreement that
preserves the claims made by the parties pending the resolution of the
litigation. On December 31, 2000, QTC gave notice of its election to exercise
its contractual right to sell its 50 percent interest in TransColorado to KNTC,
subject to the standstill agreement. A trial before the judge is scheduled to
begin April 1, 2002.
GRYNBERG. Questar defendants are involved in three separate lawsuits filed
by Mr. Grynberg, an independent producer. The first case involves claims filed
by Grynberg under the Federal False Claims Act and is substantially similar to
other cases filed against pipelines and their affiliates that have all been
consolidated for discovery and pre-trial motions in Wyoming's federal district
court. The cases involve allegations of industry-wide mismeasurement and
undervaluation of gas volumes on which royalty payments are due the federal
government. The complaint seeks treble damages and imposition of civil
penalties. The federal district judge denied the motions filed by the defendants
to dismiss the lawsuits and has not set a date for a scheduling conference.
The second case is a lawsuit that is currently on appeal before the Utah
Supreme Court. The case was dismissed by a Utah state court judge after he
granted the motion for summary judgment filed by the Questar parties. Grynberg
claims that Questar Pipeline, QGM and QET mismeasured gas volumes attributable
to his working interest in specified wells located in southwestern Wyoming. He
cites mismeasurement to support claims for breach of contract, negligent
misrepresentation, fraud, breach of fiduciary responsibilities and related
causes.
-23-
<Page>
The third case is pending in a Wyoming federal district court against
Questar Gas (as the successor to the named Questar Pipeline). The judge, in June
of 2001, entered an order granting the motion for partial summary judgment filed
by the Questar defendants that dismissed the antitrust claims from the case, but
has not ruled on other motions for summary judgment dealing with "ratable take"
and fraud.
GAS PIPELINES. Questar E&P, QGM, Wexpro, Questar Gas, and Questar Pipeline
are among the numerous defendants in this case, which is currently styled as
WILL PRICE V. GAS PIPELINES, that has been filed against the pipeline industry.
Pending in a Kansas state district court, this case is similar to the cases
filed by Grynberg, but the allegations of a conspiracy by the pipeline industry
to set standards that result in the systematic mismeasurement of natural gas
volumes and resulting underpayment of royalties are made on behalf of private
and state lessors, rather than on behalf of the federal government. The
defendants, including the Questar defendants, have filed motions to dismiss for
lack of personal jurisdiction.
DEQ PENALTIES. QMR subsidiaries have received notices of violation from the
Wyoming Department of Environmental Quality ("DEQ") in conjunction with DEQ's
program to require that all existing air-emission facilities be registered and
permitted. QMR has raised an issue concerning DEQ's failure to provide proper
notice of the new requirements and contends that existing equipment should be
"grandfathered" under DEQ's regulatory program in place at time of installation.
QMR expects that any penalties assessed its subsidiaries will not exceed
$300,000 on an aggregate basis. The penalties are assessed on a per-well or
per-facility basis and differ based on the eligibility of the facility for a
waiver or the need for appropriate action to minimize emissions. In response to
the action taken by the DEQ, QMR has made an extensive review of wells and other
facilities in Wyoming to ascertain that the necessary filings have been made and
has established procedures to make such filings on an ongoing basis.
QMR CLASS ACTION CASES. Royalty class actions are being asserted by
landowners against entities involved in the oil and gas production and marketing
businesses. The QMR group of companies has been involved in one major class
action (the Bridenstine case in Oklahoma) that was settled near the end of 2000,
reached an agreement to settle another Oklahoma case that was recently filed,
and has been named in class actions in Wyoming that have not yet been certified.
These companies believe that they will continue to be subject to other royalty
class actions.
WASATCH CHEMICAL. The Company continues to monitor the Wasatch Chemical
property in Salt Lake City, which is still included on the national priorities
list, commonly known as the "Superfund" list. The Wasatch Chemical property was
the location of chemical mixing operations and is the subject of a 1992 consent
order. Questar conducted the necessary soil remediation and groundwater
remediation activities and expects that the site will be eventually removed from
the Superfund list.
SEE "Regulated Services, Retail Distribution, Regulation" for a review of
significant regulatory proceedings and appeals from decisions in such
proceedings.
-24-
<Page>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Company did not submit any matters to a vote of stockholders during the
last quarter of 2001.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Information concerning the market for the common equity of the Company and
the dividends paid on such stock is located in Note 11 of the Notes to
Consolidated Financial Statements under Item 14. As of March 19, 2002, Questar
had 11,299 shareholders of record and estimates that it had an additional
30,000-35,000 beneficial holders.
-25-
<Page>
ITEM 6. SELECTED FINANCIAL DATA
<Table>
<Caption>
2001 2000 1999 1998 1997
-----------------------------------------------------------------
(In Thousands, Except Per Share Amounts)
Revenues $1,439,350 $1,266,153 $ 924,219 $ 906,256 $ 936,337
Operating expenses
Cost of natural gas and other products sold 675,011 562,229 352,554 367,932 399,941
Operating and maintenance 270,355 251,477 221,082 208,190 205,723
Depreciation, depletion and amortization 151,735 142,491 132,164 118,745 113,063
Other expenses 68,142 61,989 45,580 57,998 61,170
-----------------------------------------------------------------
Total operating expenses 1,165,243 1,018,186 751,380 752,865 779,897
-----------------------------------------------------------------
Operating income $ 274,107 $ 247,967 $ 172,839 $ 153,391 $ 156,440
=================================================================
Interest and other income $ 37,023 $ 39,463 $ 78,700 $ 17,021 $ 22,481
Write-down of investment in partnership (49,700)
Net income $ 158,186 $ 149,477 $ 96,852 $ 89,310 $ 98,630
Average common shares outstanding - diluted 81,658 80,915 82,676 82,817 82,668
Basic earnings per common share $ 1.95 $ 1.86 $ 1.17 $ 1.08 $ 1.20
Diluted earnings per common share $ 1.94 $ 1.85 $ 1.17 $ 1.08 $ 1.19
Dividends per share $ 0.705 $ 0.685 $ 0.67 $ 0.6525 $ 0.62
Book value per common share $ 13.26 $ 11.79 $ 10.99 $ 10.27 $ 9.79
Total assets $3,235,711 $2,472,027 $2,184,734 $2,111,540 $1,874,974
Net cash provided from operating
activities 372,674 252,067 207,331 278,005 197,596
Capital expenditures 984,086 315,142 261,983 455,477 208,359
Capitalization
Long-term debt, less current portion $ 997,423 $ 714,537 $ 735,043 $ 615,770 $ 541,986
Common stock 1,080,781 952,632 894,516 848,752 803,858
-----------------------------------------------------------------
Total capitalization $2,078,204 $1,667,169 $1,629,559 $1,464,522 $1,345,844
=================================================================
</Table>
-26-
<Page>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
RESULTS OF OPERATIONS AND FINANCIAL CONDITION
SUMMARY
Questar Corporation reported earnings of $158.2 million for 2001, up 6% compared
with earnings for 2000. Following is a year-to-year comparison of net income by
line of business.
<Table>
<Caption>
2001 2000 Change Percentage
--------------------------------------------------------------
(Dollars in thousands, except per share amounts)
Questar Market Resources $101,134 $ 77,808 $ 23,326 30%
Questar Regulated Services 58,445 54,332 4,113 8%
Corporate and Other Operations (1,393) 17,337 (18,730) -108%
---------------------------------------------
$158,186 $149,477 $ 8,709 6%
=============================================
Earnings per diluted common share $1.94 $1.85 $0.09 5%
</Table>
Questar Market Resources' net income rose 30% in 2001 compared with 2000 driven
by a 53% increase in earnings from exploration and production operations and a
16% increase in Wexpro's earnings from gas-development operations. In 2001, gas
and oil reserves grew 62% after production to nearly 1.2 trillion cubic feet
equivalent.
Questar Regulated Services reported an 8% increase in earnings for 2001 compared
with the prior year. The number of distribution customers grew by 3.9% partially
offset by lower gas usage per customer and higher bad debt expense. An increase
in transportation capacity demand was offset by ongoing legal costs and
operating losses from the TransColorado partnership.
Corporate and Other Operations, dominated by information-technology and
web-hosting activities, reported a net loss in 2001, which corresponded with the
steep decline in business activity in the electronic-business and internet
sectors. In addition, weak market values in the internet sector caused a net
loss from securities transactions in 2001.
On July 1, 2001, Questar elected to change its accounting method for gas and oil
properties from the full cost method to the successful efforts method. Prior
years financial statements have been restated in an amended Form 10-K filed for
the year ended December 31, 2000. Previously reported earnings decreased $7.2
million ($.09 per share) and $2.0 million ($.03 per share) for the years ended
December 31, 2000 and 1999, respectively.
-27-
<Page>
RESULTS OF OPERATIONS
QUESTAR MARKET RESOURCES (Market Resources or QMR) conducts Questar's
exploration and production, gas development, gathering, processing and marketing
activities. Following is a summary of financial results and operating
information.
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------------------
(In Thousands)
OPERATING INCOME
Revenues
Natural gas sales $226,656 $193,359 $125,245
Oil and natural gas liquids sales 59,482 59,901 41,521
Cost-of-service gas operations 89,934 74,492 61,705
Energy marketing 337,845 379,760 243,296
Gas gathering and processing 26,776 29,278 22,341
Other 5,704 5,263 4,203
---------------------------------------------
Total revenues 746,397 742,053 498,311
Operating expenses
Energy purchases 324,124 369,752 239,201
Operating and maintenance 112,087 106,761 79,719
Exploration 6,986 7,917 5,321
Depreciation, depletion and amortization 92,678 85,025 73,028
Abandonment and impairment of oil
and gas properties 5,171 3,418 7,535
Production and other taxes 43,125 36,262 21,516
Wexpro settlement agreement -
oil income sharing 2,885 4,758 2,292
---------------------------------------------
Total operating expenses 587,056 613,893 428,612
---------------------------------------------
Operating income $159,341 $128,160 $ 69,699
=============================================
OPERATING STATISTICS
Production volumes
Natural gas (in MMcf) 70,574 68,963 62,712
Oil and natural gas liquids (in Mbbl)
Questar E & P, SEI 2,500 2,225 2,311
Wexpro 467 521 555
Production revenue
Natural gas (per Mcf) $ 3.21 $ 2.80 $ 2.00
Oil and natural gas liquids (per bbl)
Questar E & P, SEI $ 19.22 $ 20.50 $ 13.92
Wexpro $ 24.49 $ 27.43 $ 16.84
Wexpro investment base, net
of deferred income taxes (in millions) $ 161.3 $ 124.8 $ 108.9
Energy-marketing volumes
(in thousands of equivalent dth) 91,791 105,632 112,982
Natural gas-gathering volumes (in Mdth)
For unaffiliated customers 91,729 92,969 84,961
For Questar Gas 37,161 36,791 32,050
For other affiliated customers 27,049 25,068 19,659
---------------------------------------------
Total gathering 155,939 154,828 136,670
=============================================
Gathering revenue (per dth) $ 0.13 $ 0.13 $ 0.15
</Table>
-28-
<Page>
REVENUES
Revenues were 1% higher in 2001 when compared with 2000 as a result of increased
production, higher gas prices and increased investment in gas-development
activities. Market Resources produced 85.6 billion cubic feet equivalent (Bcfe)
in 2001 compared with 82.3 Bcfe in 2000 due to the acquisition of Shenandoah
Energy Inc. (SEI) on July 31, 2001. Gas production increased 2% over year
earlier levels while average realized selling prices rose 15%. Production of oil
and natural gas liquids (NGL) rose 12%, excluding Wexpro. Energy-marketing
volumes dropped 13% in 2001 compared with 2000. In 2001, declining prices for
plant products and higher gas prices were responsible for reduced revenues and
lower margins from processing plants.
Market Resources enters hedging transactions to support earnings targets and to
protect earnings from downward moves in commodity prices. In 2001, approximately
59% of equity gas production and 58% of oil production, excluding Wexpro, was
hedged. This compares with 2000 when approximately 53% of gas production and 73%
of oil production was priced under hedging contracts. In 2001, the average price
received from hedging transactions was $2.99 per Mcf of gas, net to the well,
and $18.28 per barrel of oil, net to the well. Hedging activities reduced 2001
revenues from gas sales by $44.7 million and oil sales by $9.8 million.
Revenues from cost-of-service operations were 21% higher in both 2001 and 2000
when compared with prior years. Wexpro operates and develops oil and natural gas
properties on behalf of Questar Gas and receives a return on its investment in
successful wells in addition to being reimbursed for operating expenses. The
natural gas produced from these properties is delivered to Questar Gas at
Wexpro's cost of service. Oil is sold at market prices. Any net income from oil
sales remaining after recovery of expenses and Wexpro's return on investment is
shared between Wexpro and Questar Gas. Questar Gas' portion is reported as
oil-income sharing on the income statement. Wexpro's investment base, net of
deferred income taxes, grew 29% and 15% in 2001 and 2000, respectively. The
return on average investment base was 19.7% in 2001 and 19.5% in 2000.
Revenues increased 49% in 2000 when compared with 1999 due primarily to higher
energy prices and increased gas production. Natural gas prices began rising in
the second half of 2000 and spiked in the first quarter of 2001 due to an energy
shortage in the western United States. Natural gas production rose 10% as a
result of acquiring Canadian producing properties in January 2000.
OPERATING EXPENSES
Operating and maintenance (O&M) expenses were 5% higher in 2001 when compared
with 2000 due primarily to an increase of the number of gas and oil properties
operated following the acquisition of SEI. O&M expenses increased 34% in 2000
compared with 1999 due primarily to an increase in the number of gas and oil
properties and to the costs of litigating and settling a major lawsuit.
Exploration expense, largely a function of drilling dry exploratory wells,
decreased 12% in 2001 after increasing 49% in 2000. Depreciation, depletion and
amortization expense (DD&A) increased 9% in 2001 due to a 4% increase in gas and
oil production and a higher average rate. The average DD&A rate for oil and gas
properties was $.83 per thousand cubic feet equivalent (Mcfe) for 2001, up from
$.78 per Mcfe in 2000 and $.71 per Mcfe in 1999. Production and other taxes rose
19% in 2001 and 69% in 2000 driven by higher revenues and prices.
ENRON EXPOSURE
A QMR energy-marketing affiliate has bought and sold natural gas and engaged in
energy trading activities with affiliates of Enron. At the time of Enron's
announced plan and filing to seek protection under bankruptcy laws, Enron owed
QMR $3.0 million for gas purchased from QMR and QMR owed Enron $.8 million for
gas purchased from Enron. In addition, QMR owed $.8 million to Enron in a
terminated swap contract. It is the opinion of QMR's counsel that these
transactions may be netted. QMR has reserved the net amount of these balances or
$1.4 million.
-29-
<Page>
NONREGULATED GAS AND OIL RESERVES
In 2001, gas and oil reserves grew 62% after production to nearly 1.2 trillion
cubic feet through a combined strategy of acquiring reserves and a successful
drilling program. Market Resources achieved a 631% reserve replacement ratio in
2001 compared with 261% in 2000. QMR acquired 415 Bcfe of proved gas and oil
reserves in the SEI acquisition. Reserve additions, revisions and purchases, and
sales in place, amounted to 540 Bcfe in 2001. In January 2001, Market Resources
completed the sale of 290 producing properties and a gas gathering system in the
Midcontinent. Daily production volumes approximated 4.3 MMcf of gas and 180
barrels of oil.
The five-year average finding cost was $.85 per Mcfe in 2001 compared with $.86
in 2000 and $.90 in 1999, excluding Wexpro.
QUESTAR REGULATED SERVICES (Regulated Services) conducts Questar's natural
gas-distribution, transmission, storage, processing and nonregulated energy
services.
Natural Gas Distribution - Questar Gas conducts natural gas distribution
operations. Following is a summary of financial results and operating
information:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
-------------------------------------
(In Thousands)
OPERATING INCOME
Revenues
Residential and commercial sales $618,451 $467,293 $396,882
Industrial sales 56,200 38,993 28,938
Industrial transportation 7,233 6,968 6,594
Other 22,229 23,508 17,523
-------------------------------------
Total revenues 704,113 536,762 449,937
Natural gas purchases 498,545 334,193 257,265
-------------------------------------
Margin 205,568 202,569 192,672
Operating expenses
Operating and maintenance 103,427 101,486 103,308
Depreciation and amortization 35,030 34,450 36,426
Other taxes 8,729 10,213 7,625
-------------------------------------
Total operating expenses 147,186 146,149 147,359
-------------------------------------
Operating income $ 58,382 $ 56,420 $ 45,313
=====================================
OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales 83,650 83,373 82,201
Industrial deliveries
Sales 10,684 10,314 9,823
Transportation 54,624 54,836 51,643
-------------------------------------
Total industrial 65,308 65,150 61,466
-------------------------------------
Total deliveries 148,958 148,523 143,667
=====================================
</Table>
-30-
<Page>
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------------------
Natural gas revenue (per dth)
Residential and commercial $ 7.39 $ 5.60 $ 4.83
Industrial sales 5.26 3.78 2.95
Transportation for industrial customers 0.13 0.13 0.13
System natural gas cost (per dth) $ 4.92 $ 3.54 $ 2.61
Heating degree days (normal 5,609) 5,487 5,402 5,317
Warmer than normal 2% 4% 5%
Usage per customer (dth) 121.0 126.2 128.5
Number of customers at December 31,
Residential and commercial 730,579 703,306 684,950
Industrial 1,321 1,323 1,367
---------------------------------------------
731,900 704,629 686,317
=============================================
</Table>
MARGIN (REVENUES LESS NATURAL GAS PURCHASES)
Questar Gas' margin was 1% higher in 2001 when compared with 2000 and 5% higher
in 2000 when compared with 1999. The higher margins were primarily the result of
a $13.5 million annualized general rate increase in Utah, effective August 11,
2000, and a 3.9% larger customer base. An acquisition of two small distribution
systems accounted for 10,500 of the 27,271 increase in customers.
Usage per residential customer has been steadily declining for the past several
years in large part as a result of higher energy prices and more
energy-efficient appliances and home construction. Usage, calculated on a
temperature adjusted basis, has decreased by 4%, 2% and 1% in 2001, 2000 and
1999, respectively. Temperatures in 2001 were near normal; however, temperatures
have been warmer than normal for nine of the last ten years. The financial
impact of actual weather variations from normal are minimized by a
weather-normalization adjustment in rates.
Industrial deliveries were flat in 2001 and 6% higher in 2000. An increase in
natural gas volumes used to generate electricity offset lower deliveries to a
steel producer. In 2002, the steel producer announced plans to reorganize under
protection of bankruptcy laws. Margins from gas delivered to industrial
customers are substantially lower than margins from gas delivered to residential
and commercial customers.
A significant increase in purchased-gas costs in the second half of 2000 and the
first quarter of 2001 resulted in higher charges to customers but did not
directly affect the margin. The recovery of gas costs is authorized through rate
regulation in Utah and Wyoming. Gas costs in Utah rates, which peaked at $4.67
per dth in a January 1, 2001 filing, have subsided to $2.68 per dth in a January
1, 2002 gas-cost filing. In 2001, 44% of Questar Gas' supplies came from
company-owned reserves, which cost less than gas purchased from third-party
suppliers.
OPERATING EXPENSES
Operating and maintenance expenses were 2% higher in 2001 due largely to a $3.7
million increase in bad debt expenses that more than offset labor savings from a
fourth-quarter 2000 early-retirement program. An economic recession, increased
number of bankruptcies and higher energy costs resulted in more frequent
collection problems. O & M expenses were 2% lower in 2000 when compared with
1999 due to lower legal costs and reduced information-technology expenses.
Depreciation expense increased 2% in 2001 due to capital spending. Depreciation
expense was $2.8 million lower in 2000 due to investments in several information
systems being fully depreciated. In 2000, other taxes increased when compared
with 1999 because of a $1.4 million adjustment of prior-year taxes.
-31-
<Page>
Natural Gas Transmission - Questar Pipeline conducts natural gas-transmission,
storage and processing operations. Following is a summary of financial results
and operating information:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------------------
(In Thousands)
OPERATING INCOME
Revenues
Transportation $ 77,002 $ 72,547 $ 69,885
Storage 37,828 37,711 37,647
Processing 7,543 6,763 3,570
Other 2,520 2,055 1,058
---------------------------------------------
Total revenues 124,893 119,076 112,160
Operating expenses
Operating and maintenance 47,244 43,761 38,534
Depreciation and amortization 15,407 15,391 16,743
Other taxes 2,920 3,071 2,488
---------------------------------------------
Total operating expenses 65,571 62,223 57,765
---------------------------------------------
Operating income $ 59,322 $ 56,853 $ 54,395
=============================================
OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers 195,610 158,604 135,886
For Questar Gas 110,259 108,183 105,499
For other affiliated customers 6,892 8,370 12,153
---------------------------------------------
Total transportation 312,761 275,157 253,538
=============================================
Transportation revenue (per dth) $ 0.25 $ 0.26 $ 0.28
</Table>
REVENUES
Transportation volumes rose 14% in 2001 to reach 313 million dth after posting a
9% increase to 275 million dth in 2000. Not only are the volumes of gas
transportation increasing, but the proportion of firm volumes to interruptible
volumes is increasing. Firm transportation volumes, whose customers pay a fixed
rate to reserve a portion of pipeline capacity, increased to 94% of the total in
2001 compared with 92% the previous year. The increase in firm transportation
reflects a growing demand for gas for power generation and growing pipeline
capacity. Main Line 104, a 77 mile extension in central Utah with a 272,000 dth
per day capacity, began operations in November 2001 and is fully subscribed.
As of December 31, 2001, approximately 77% of Questar Pipeline's transportation
system was reserved by firm-transportation customers under contracts with
varying terms and lengths. Questar Gas continues to be Questar Pipeline's single
largest transportation customer accounting for 70% of the demand charges
collected. Questar Gas has reserved transportation capacity of 899,000 dth per
day, representing 61% of the total reserved daily-transportation capacity as of
December 31, 2001. Questar Gas' transportation contracts have been extended with
initial terms ending in 2006 to 2017.
Revenues from storage operations remained unchanged in the three-years ending
December 31, 2001. Questar Pipeline's primary storage facility at Clay Basin has
been 100% subscribed under long-term contracts for several years. A majority of
the storage contracts have terms in excess of eight years. The Clay Basin
storage facility in eastern Utah was last expanded by 5 Bcf in May of 1998.
Questar Gas has contracted for 26% of firm-storage capacity for terms extending
from 2008 to 2019.
A processing plant owned by Questar Transportation Services, which removes
carbon dioxide from a portion
-32-
<Page>
of the gas stream, completed its second year of operation in 2001.
OPERATING EXPENSES
Operating and maintenance expenses increased 8% in 2001 compared with 2000 due
primarily to rising legal costs and information system maintenance. These
increases more than offset labor savings from an early retirement program
offered in the fourth quarter of 2000. Higher legal costs and a full year of
expenses associated with a gas-processing plant were responsible for the 14%
increase in O&M expense in 2000 compared with 1999. The estimated useful life of
a processing plant that removes carbon dioxide from the gas stream was increased
from 10 to 20 years resulting in a $1.3 million reduction of depreciation
expense in 2000. Because processing fees are determined on a cost-of-service
basis, the lower depreciation expense resulted in a $1.3 million refund to
Questar Gas, the primary customer of processing services.
TRANSCOLORADO LITIGATION
Questar TransColorado, Inc. (QTC), a subsidiary of Questar Pipeline, and KN
TransColorado, Inc. (KNTC), a subsidiary of Kinder Morgan, are partners in the
TransColorado Gas Transmission Company (TransColorado). The partners are
involved in a complex lawsuit pending in a Colorado state district court. At the
center of the lawsuit is the validity of a contractual right claimed by QTC to
put its 50% interest in TransColorado to KNTC during the 12-month period
beginning March 31, 2001. The amount that QTC believes it is entitled to receive
under the put is $118 million. QTC and KNTC entered a standstill agreement
regarding various issues in the litigation. QTC provided notice to KNTC that it
elected to put its interest in TransColorado as of March 31, 2001, were it not
for the provisions of the standstill agreement. The trial is scheduled to
commence on April 1, 2002.
CORPORATE AND OTHER OPERATIONS - This business segment is responsible for
information-technology and communications services and corporate administration.
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------------------
(In Thousands)
OPERATING INCOME
Revenues $67,772 $73,409 $57,679
Operating expenses
Cost of products sold 25,949 24,640 9,651
Operating and maintenance 35,127 33,506 37,516
Depreciation and amortization 6,183 5,937 5,837
Amortization of goodwill 2,224 1,653 116
Other taxes 1,144 1,073 1,071
---------------------------------------------
Total operating expenses 70,627 66,809 54,191
---------------------------------------------
Operating income (loss) $(2,855) $ 6,600 $ 3,488
=============================================
</Table>
REVENUES
Revenues decreased 8% in 2001 caused by a decline in internet services,
electronic business and information technology services. The gross margin on
products and services sold amounted to $5.4 million, $7.0 million and $1.1
million in 2001, 2000 and 1999, respectively.
OPERATING EXPENSES
Operating and maintenance expenses were 5% higher in 2001 when compared with
2000 because of a $1.8 million restructuring charge recorded by Consonus, a
subsidiary of Questar InfoComm. O&M expenses were 11% lower in 2000 when
compared with 1999. A $2.9 million charge associated with an early retirement
program was recorded in 1999 when 50 employees elected to retire. Labor savings
from the workforce reduction was approximately $2.8 million in 2000.
Amortization of goodwill resulted from the acquisition of Consonus in 2000.
After January 1, 2002, amortization of goodwill will no longer be permitted
under new accounting rules.Instead
-33-
<Page>
goodwill will be subjected to a yearly test to determine if the book value
exceeds a calculated fair value. It is likely that a portion or all of the $18.2
million of goodwill at Consonus will be impaired under this new test during the
first quarter of 2002.
CONSOLIDATED OPERATING RESULTS
REVENUES
Consolidated revenues increased 14% in 2001 compared with 2000 as a result of
higher gas prices and gas production for exploration and production operations
and a higher gas-cost component in natural gas distribution rates. Reduced
energy marketing volumes resulted in lower revenues from these activities in
2001. Consolidated revenues rose 37% in 2000 compared with 1999 as a result of
higher energy prices, a 10% increase in gas produced from nonregulated sources
and a boost in revenues from e-commerce business. Higher energy prices increased
revenues from gas and oil production, energy marketing, natural gas distribution
and gas processing.
COST OF NATURAL GAS AND OTHER PRODUCTS SOLD
Gas costs rose significantly in the first quarter of 2001 when a majority of
natural gas distribution sales occur. By the end of 2001, gas costs had fallen
dramatically from a first quarter high point. The increase in energy prices
began in the last half of 2000 precipitated by an energy shortage in the western
United States. The cost of natural gas purchased for resale to distribution
customers and energy purchases in energy marketing transactions increased
significantly.
OPERATING AND MAINTENANCE
Operating and maintenance expenses increased by 8% in 2001 compared with 2000 as
a result of an increase in the number of gas and oil properties operated by QMR
due to the acquisition SEI, higher bad debt expenses, legal costs and
software-program maintenance. Operating and maintenance expenses increased by
14% in 2000 when compared with 1999 because of the increase in the number of
producing properties, litigation and settlement of a major lawsuit involving
affiliates of Market Resources, and a lawsuit involving an affiliate of Questar
Pipeline.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased 6% in 2001 when compared with
2000 as a result of increased gas production and investment in depreciable
assets. The average DD&A rate for oil and gas wells was $.83 Mcfe in 2001, up
from $.78 per Mcfe in 2000. Depreciation, depletion and amortization increased
8% in 2000 when compared with 1999 and the average DD&A rate for oil and gas
wells was $.78 per Mcfe in 2000, up from $.71 per Mcfe in 1999. Software that
reached the end of its depreciable life and an increase in the estimated useful
life of a processing plant resulted in a $4.1 million reduction of 2000
depreciation expense.
EXPLORATION AND ABANDONMENT AND IMPAIRMENT OF OIL AND GAS PROPERTIES
Exploration expense decreased in 2001compared with 2000 because of a reduction
in the number of dry exploratory wells drilled. Leasehold impairments increased
in 2001. Exploration expense increased 49% in 2000 compared with 1999 primarily
as a result of drilling dry exploratory wells.
PRODUCTION AND OTHER TAXES
Production and property taxes increased in 2001 and 2000 because of higher
revenues from rising gas prices and production. Rising property values caused
higher property taxes in 2000.
-34-
<Page>
INTEREST AND OTHER INCOME
Gains from selling non-strategic properties amounted to a $21.8 million pretax
gain in 2001 ($13.5 million after tax), including the sale of a home security
business for a $964,000 pretax gain. Gains from selling securities of other
companies were a prominent part of interest and other income recorded in 2000
and 1999. However, the level of securities sales dropped in 2001 and 2000
because of the general decline in market value of technology companies. In 2001,
an other-than-temporary decline in the market value of technology stock held by
the Company resulted in a $1.5 million write down. Sales of securities generated
a pretax gain of $26.5 million ($16.3 million after tax) in 2000 and a pretax
gain of $60.7 million ($36.9 million after tax) in 1999.
<Table>
<Caption>
Year ended December 31,
2001 2000 1999
---------------------------------------------
(In Thousands)
Gain (loss) from property sales $21,753 $(1,784) $ 6,242
Gain (loss) from securities transactions (1,461) 26,523 60,720
Interest income and other earnings 4,725 7,621 7,367
Minority interest 1,725 104 (26)
Allowance for other funds used during
construction 5,481 4,476 2,017
Returns earned on working-gas inventory
and purchased-gas adjustment account 4,800 2,523 2,380
---------------------------------------------
Total $37,023 $39,463 $78,700
=============================================
</Table>
OPERATIONS OF UNCONSOLIDATED AFFILIATES
Earnings from unconsolidated affiliates, partnerships in which the Company holds
an interest but are not consolidated for financial reporting purposes, were
lower in 2001 because of TransColorado's $2.2 million operating loss. No
TransColorado operating losses were reported in 2000 and Questar's share of
TransColorado's operating loss for 1999 was $5.9 million.
DEBT EXPENSE
In 2001, lower short-term interest rates were more than offset by increased
borrowings resulting in an increase in debt expense. In 2000, interest expense
increased due to higher short- and long-term borrowing and higher interest
rates.
INCOME TAXES
The effective combined federal, state and foreign income tax rate was 35.8% in
2001, 34.4% in 2000 and 32.5% in 1999. Income tax rates were below the combined
statutory rate of about 38% primarily due to non-conventional fuel credits,
which amounted to $6.8 million in 2001, $6.5 million in 2000 and $7.2 million in
1999. In addition, a Colorado state income tax credit derived from conducting
business in a designated enterprise zone reduced state income taxes by $3.2
million in 2000.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------------------
(In Thousands)
Net income $158,186 $149,477 $ 96,852
Non-cash adjustments to net income 177,914 173,428 135,981
Changes in operating assets and liabilities 36,615 (70,838) (25,502)
---------------------------------------------
Net cash provided from operating activities $372,715 $252,067 $207,331
=============================================
</Table>
-35-
<Page>
Net cash provided from operating activities increased 48% in 2001 when compared
with 2000 due primarily to changes in operating assets and liabilities and
higher net income. Increased cash flows in 2001, resulted from the collection of
accounts receivable and the return of interest-bearing deposits with energy
brokers. Net cash provided from operating activities increased 22% in 2000
compared with 1999 due largely to higher net income.
INVESTING ACTIVITIES
Capital spending amounted to $984.1 million and reflects several large
transactions in addition to ongoing plant expansion. The details of capital
expenditures are as follows:
<Table>
<Caption>
Year Ended December 31,
2002
Forecast 2001 2000
---------------------------------------------
(In Thousands)
Questar Market Resources
Exploratory drilling $ 500 $ 4,090 $ 446
Development drilling 142,600 188,091 97,361
Other exploration 2,100 1,433 342
Reserve acquisitions 100 370,068 65,130
Production 4,700 7,624 8,382
Gathering and processing 27,300 53,914 3,330
Storage 11,754 11,513
General 2,800 1,533 855
---------------------------------------------
180,100 638,507 187,359
Questar Regulated Services
Natural gas distribution
Distribution system and
customer additions 55,100 62,266 49,454
General 13,500 16,525 16,313
---------------------------------------------
68,600 78,791 65,767
Natural gas transmission
Transmission system 21,700 103,218 15,312
Storage 19,800 9,389 333
Partnerships 4,000 104,701 9,024
Southern Trails Pipeline 30,000 32,418 13,975
Gathering and processing 400 6,523 250
General 6,500 454 4,141
---------------------------------------------
82,400 256,703 43,035
Other 14,300 2,860 1,167
---------------------------------------------
Total Questar Regulated Services 165,300 338,354 109,969
Corporate and other operations
Electronic commerce 1,500 1,033 12,878
Communications and technology 1,500 5,012 1,317
General 27,200 1,180 3,619
---------------------------------------------
30,200 7,225 17,814
---------------------------------------------
Total capital expenditures $375,600 $984,086 $315,142
=============================================
</Table>
-36-
<Page>
QUESTAR MARKET RESOURCES
QMR acquired SEI for $403 million including debt and received 415 Bcfe of proved
oil and gas reserves, gas processing capacity of 100 MMcf per day, 90 miles of
gathering lines, 114,000 net acres of undeveloped leasehold acreage and four
drilling rigs. In addition, QMR participated in drilling 337 wells (130 net
wells) that resulted in 113 net gas wells, 10 net oil wells and 7 net dry holes.
There were 56 gross wells in progress at year end. The success rate of completed
net wells was 95%. QMR invested $7.7 million in the Rendezvous partnership that
will provide gas gathering and compression services in southwestern Wyoming.
QUESTAR REGULATED SERVICES - NATURAL GAS DISTRIBUTION
The distribution system was extended by 1,145 miles of main, feeder and service
lines to accommodate the addition of 27,271customers. This includes $10.9
million for the acquisition of two small distribution systems.
QUESTAR REGULATED SERVICES - NATURAL GAS TRANSMISSION
Construction was completed on Main Line 104, a 77-mile pipeline in central Utah
that cost $95.4 million. Questar Pipeline borrowed $100 million and used the
proceeds to repay debt, through a wholly-owned subsidiary, Questar
TransColorado, Inc. (QTC), owed by TransColorado Gas Transmission Company.
FINANCING ACTIVITIES
Record capital spending and refinancing callable debt to take advantage of low
interest rates combined to make 2001 a very active financing year. Net cash
provided from operating activities of $372.7 million and proceeds from the sale
of non-strategic assets supplied 43% of the funding needed for capital
expenditures. The remaining 57% was supplied through short- and long-term debt
offerings. QMR borrowed $415 million, $280 million of which was in the form of a
short-term bridge loan, to finance its acquisition of SEI. A portion of the
bridge loan was subsequently refinanced with a one-year callable commercial
paper note in the amount of $220 million. The commercial paper note was
partially repaid with the proceeds of $200 million of five-year private
placement notes with a 7% interest rate, issued January 16, 2002. The terms of
the private placement notes require registration of the notes with the
Securities and Exchange Commission (SEC). A registration statement was filed
February 22, 2002 that became effective March 4, 2002. The exchange notes are
expected to be issued in April 2002. In March 2001, QMR sold $150 million of
10-year notes with a 7.5% interest rate and used the proceeds to reduce debt.
Questar Pipeline issued $180 million of 10-year medium-term notes with a
weighted average coupon rate of 6.86%. In 2001, Questar Pipeline repaid the
remaining balances of its 9 7/8% and 9 3/8% debentures, totaling $115 million
with a weighted average interest rate of 9.5%. In 2001, Questar Gas sold $60
million of 11-year medium-term notes with a 6.3% interest rate.
Short-term borrowings amounted to $405.5 million of commercial paper, including
$220 million borrowed by QMR, and $124.7 million of bank loans at December 31,
2001. Included with the bank loans is $100 million borrowed by Questar Pipeline
to refinance 50% of a loan held by the TransColorado partnership that matured
October 2001. A year earlier, short-term debt included $181.1 million of
commercial paper and $28 million of bank loans. The weighted average interest
rate on balances at December 31 was 2.27% in 2001 and 6.68% in 2000.
Parent-company commercial-paper borrowings are backed by short-term
line-of-credit arrangements and are rated P1 and A1 by Moody's and Standard and
Poor's, respectively. Market Resources has an unrated commercial-paper program
with a $100 million capacity. Market Resources' commercial-paper borrowings are
limited to and supported by available capacity on Market Resources' existing
revolving credit facility. Market Resources had a commercial-paper balance of
$12.5 million that was included in the total $181.1 million balance at December
31, 2000 and no amounts borrowed under its commercial paper program at December
31, 2001.
Questar's consolidated capital structure consisted of 48% long-term debt and 52%
common shareholders' equity at December 31, 2001. Including short-term debt,
leverage was 59%. The Company is taking measures to reduce its leverage to the
range of 50% and maintain its debt ratings. Moody's and Standard and Poor's have
rated the long-term debt of Questar Gas and Questar Pipeline A1 and A+,
respectively.Questar Market
-37-
<Page>
Resources' debt rating is BBB+ by Standard and Poor's and Baa2 by Moody's.
Critical Accounting Policies
The Company's consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States. Management
believes the following accounting policies may involve a higher degree of
complexity and judgment.
SUCCESSFUL EFFORTS ACCOUNTING FOR GAS AND OIL OPERATIONS
Under the successful efforts method of accounting, the Company capitalizes the
costs of acquiring leaseholds, drilling development wells and successful
exploratory wells and purchasing related support equipment and facilities. The
costs of unsuccessful exploratory wells are charged to expense when it is
determined that such wells have not located proved reserves. Unproved leaseholds
costs are periodically reviewed for impairment. Costs related to impaired
prospects are charged to expense. Costs of geological and geophysical studies
and other exploratory activities are expensed as incurred. Costs associated with
production and general corporate activities are expensed in the period incurred.
The Company recognizes gain or loss on the sale of properties on a field basis.
Capitalized proved leasehold costs are depleted on the unit-of-production method
based on proved reserves on a field basis. All other capitalized costs
associated with oil and gas properties are depreciated on the unit-of-production
method based on proved developed reserves on a field basis. The Company engages
independent consultants to calculate gas and oil reserves. Reserve estimates are
based on a complex and highly interpretive process that is subject to continuous
revision as additional production and development-drilling information becomes
available.
WEXPRO SETTLEMENT AGREEMENT
Wexpro's operations are subject to the terms of the Wexpro settlement agreement.
The agreement was effective August 1, 1981, and sets forth the rights of Questar
Gas' utility operations to share in the results of Wexpro's operations and the
rate of return that Wexpro will earn for managing Questar Gas' reserves. The
agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme
Court of Utah in 1983.
ACCOUNTING FOR DERIVATIVES
On January 1, 2001, the Company adopted the accounting provisions of SFAS 133,
as amended, "Accounting for Derivative Instruments and Hedging Activities." SFAS
133 addresses the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts. Under the standard, the
Company is required to carry all derivative instruments in the balance sheet at
fair value. The accounting for changes in fair value, which result in gains or
losses, of a derivative instrument depends on whether such instrument has been
designated and qualifies as part of a hedging relationship and, if so, depends
on the reason for holding it. The Company structured virtually all of its energy
derivative instruments as cash flow hedges. Any changes in the fair value of
cash flow hedges are recorded on the balance sheet until the underlying gas or
oil is produced.
The cumulative effect of this accounting change decreased other comprehensive
income by $79.4 million (after tax) and did not have a material effect on income
at adoption. Of the cumulative effect recorded in other comprehensive income,
$44.6 million (after tax) was reclassified into the Consolidated Income
Statement during 2001.
REVENUE RECOGNITION
Revenues are recognized in the period that services are provided or products are
delivered. The Company's exploration and production operations use the sales
method of accounting for gas revenues, whereby revenue is recognized on all gas
sold to purchasers. A liability is recorded to the extent that the Company has
an imbalance in excess of its share of remaining reserves in an underlying
property.
-38-
<Page>
RATE REGULATION
Rate regulatory agencies establish rates for the storage, transportation and
sale of natural gas. The regulatory agencies also regulate, among other things,
the extension and enlargement or abandonment of jurisdictional natural gas
facilities. Regulation is intended to permit the recovery, through rates, of the
cost of service, including a return on investment. The financial statements of
rate-regulated businesses are presented in accordance with regulatory
requirements. Methods of allocating costs to time periods, in order to match
revenues and expenses, may differ from those of other businesses because of
cost-allocation methods used in establishing rates.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Questar's primary market-risk exposures arise from commodity-price changes for
natural gas, oil and other hydrocarbons and changes in long-term interest rates.
The Company has an investment in a foreign operation that may subject it to
exchange-rate risk. A Market Resources subsidiary has long-term contracts for
pipeline capacity for the next several years and is obligated to pay for
transportation services with no guarantee that is will be able to recover the
full cost of these transportation commitments.
HEDGING POLICY
The Company has established policies and procedures for managing commodity price
risks through the use of commodity-based derivative arrangements. Primary
objectives of these hedging transactions are to support the Company's earnings
targets and to protect earnings from falling commodity prices. The Company will
target between 50 and 75% of the current year's production to be hedged at or
above budget levels by the end of March in the current year. The Company will
ladder in these hedges, to reach forward beyond the current year when price
levels are attractive. The volume of production hedged and the mix of derivative
instruments employed are regularly evaluated and adjusted by management in
response to changing market conditions and reviewed periodically by the Board of
Directors. Additionally, under the terms of the Market Resources' revolving
credit facility, not more than 75% of Market Resources' production quantities
can be committed to hedge arrangements. The Company does not enter into
derivative arrangements for speculative purposes.
ENERGY-PRICE RISK MANAGEMENT
Oil and natural gas prices fluctuate in response to changes in supply and
demand. Market Resources bears a majority of the risk associated with commodity
price changes and uses hedge arrangements in the normal course of business to
limit the risk of adverse price movements. However, these same arrangements
usually limit future gains from favorable price movements.
Market Resources held hedge contracts covering the price exposure for about 70.2
million dth of gas and 1.1 million bbl of oil at December 31, 2001. A year
earlier the contracts covered 50.5 million dth of natural gas and 1 million bbl
of oil. The hedging contracts exist for a significant share of equity gas and
oil production and for a portion of gas-marketing transactions. The contracts at
December 31, 2001, had terms extending through December 2003, with about 75% of
those contracts expiring by the end of 2002.
The undiscounted mark-to-market adjustment of financial gas and oil
price-hedging contracts at December 31, 2001 was a positive $37.7 million. A 10%
decline in gas and oil prices would add $14.8 million to the mark-to-market
calculation; while a 10% increase in prices would deduct $14.8 million. The
mark-to-market adjustment of gas and oil price-hedging contracts at December 31,
2000 was a negative $98 million. A 10% decline in gas and oil prices at that
time would decrease the mark-to-market adjustment by $18.1 million to $79.9
million. Conversely, a 10% increase in prices would have resulted in an $18.1
million negative mark-to-market adjustment to a negative $116.1 million balance
at that date. The calculations reflect energy prices posted on the NYMEX,
various "into the pipe" postings, and fixed prices on the indicated dates. These
sensitivity calculations do not consider changes in the fair value of the
corresponding scheduled physical transactions
-39-
<Page>
(i.e., the correlation between the index price and the price to be realized for
the physical delivery of gas or oil production), which should largely offset the
change in value of the hedge contracts. Also, the sensitivity measures exclude
mark-to-market calculations on physical hedge contracts, where settlement is
achieved through delivery of the gas or oil as opposed to cash settlements with
a counterparty.
QUESTAR GAS ENERGY-PRICE RISK MANAGEMENT
Questar Gas will continue to pursue hedging activities to mitigate energy-price
fluctuations for gas-distribution customers. The PSCU has agreed that the
benefits and the costs of hedging are to be included in the purchased-gas
adjustment account. The stipulation allows Questar Gas to record mark-to-market
adjustments for hedging contracts in the purchased-gas adjustment account. The
PSCW also allows the inclusion of hedging activities in the purchase-gas
adjustment account.
LIQUIDITY ACCELERATORS
QMR has entered into commodity price hedging contracts with several
counterparties. The counterparties are banks and energy trading firms. In some
contracts the amount of credit allowed before QMR must post collateral for
out-of-the-money hedges varies depending on the credit rating of QMR's debt. In
cases where this arrangement exists, if QMR's credit ratings fall below
investment grade (BBB- by Standard & Poor's or Baa3 by Moody's) counterparty
credit generally falls to zero.
Questar sold a parking lot in 2001 and as a condition of the sale, indemnified
the buyer for parking rents, costs of restoration of the parking lot and
disposal expenses required by any applicable government agency as the result of
an environmental study, if contamination exists. The drilling of several test
holes, in a Phase II Environmental Study, did not locate any hazardous wastes or
toxic substances in concentrations requiring remediation. There are no financial
limitations on Questar's guaranty.
INTEREST-RATE RISK MANAGEMENT
The Company owed $999.5 million of long-term debt at December 31, 2001, of which
$745.5 million was fixed-rate debt. The fair value of fixed-rate debt is subject
to change as interest rates fluctuate. The fair value of Questar's long-term
debt amounted to $1,011.5 million at December 31, 2001. The Company owed $714.9
million of long-term debt at December 31, 2000, of which $470.5 million was
fixed-rate debt. The fair value of Questar's long-term debt amounted to $735.6
million at December 31, 2000. The fair-value calculation was based upon quoted
market prices and the discounted present value of cash flows using the Company's
current borrowing rates. If interest rates declined by 10%, fair value would
increase to $1,053.0 million in 2001 and $758.4 million in 2000 and interest
costs paid on variable-rate long-term debt would decrease about $.7 million. The
sensitivity calculations do not represent the cost to retire the debt
securities. The book value of variable-rate debt approximates fair value.
SECURITIES AVAILABLE FOR SALE
Securities available for sale represent equity instruments, primarily of
communications and technology companies, traded on national exchanges. The value
of these investments is subject to day to day market volatility. A 10% change in
prices would result in a change in value of $1.4 million based on prices in 2001
and $3.3 million in based on prices in 2000. A majority of the shares held by
the Company are trading near cost basis. The SEC has determined that trading
below cost basis for two consecutive quarters constitutes an impairment that
must be recognized in earnings.
FOREIGN CURRENCY RISK MANAGEMENT
The Company does not hedge the foreign currency exposure of its foreign
operation's net assets and long-term debt. Long-term debt held by the foreign
operation amounting to $61.1 million (U.S.) is expected to be repaid from future
operations of the foreign company.
-40-
<Page>
Forward-Looking Statements
This report includes "forward-looking statements" within the meaning of Section
27(a) of the Securities Act of 1933, as amended, and Section 21(e) of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included or incorporated by reference in this
report, including, without limitation, statements regarding the Company's future
financial position, business strategy, budgets, projected costs and plans and
objectives of management for future operations, are forward-looking statements.
In addition, forward-looking statements generally can be identified by the use
of forward-looking terminology such as "may", "will", "could", "expect",
"intend", "project", "estimate", "anticipate", "believe", "forecast", or "
"continue" or the negative thereof or variations thereon or similar terminology.
Although these statements are made in good faith and are reasonable
representations of the Company's expected performance at the time, actual
results may vary from management's stated expectations and projections due to a
variety of factors.
Important assumptions and other significant factors that could cause actual
results to differ materially from those expressed or implied in forward-looking
statements include changes in general economic conditions, gas and oil prices
and supplies, competition, rate-regulatory issues, regulation of the Wexpro
settlement agreement, availability of gas and oil properties for sale or for
exploration and other factors beyond the control of the Company. These other
factors include the rate of inflation, quoted prices of securities available for
sale, the weather and other natural phenomena, the effect of accounting policies
issued periodically by accounting standard-setting bodies, and adverse changes
in the business or financial condition of the Company.
-41-
<Page>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements required by this Item are submitted in a
separate section of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
The Company has not changed its independent auditors or had any
disagreements with them concerning accounting matters and financial statement
disclosures within the last 24 months.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information requested in this item concerning Questar's directors
is presented in the Company's definitive Proxy Statement under the section
entitled "Election of Directors" and is incorporated herein by reference. A copy
of the definitive Proxy Statement will be filed with the Securities and Exchange
Commission on or about April 8, 2002.
The following individuals are serving as executive officers of the
Company:
<Table>
<Caption>
PRIMARY POSITIONS HELD WITH
---------------------------
NAME THE COMPANY AND AFFILIATES
- ---- --------------------------
R. D. Cash 59 Chairman of the Board of Directors (May 1985); President and Chief Executive Officer,
Director (May 1984); President (May 1984 to February 2001); Chairman of the Boards of
Directors, all affiliates except QET and Consonus.
Keith O. Rattie 48 President and Chief Operating Officer, Director (February 2001); Vice Chairman and Director,
QRS, QMR, Questar Gas, Questar Pipeline, and most affiliates (February 2001); Chairman,
Consonus (May 2001).
G. L. Nordloh 54 President and Chief Executive Officer, all Market Resources affiliates (at various times
beginning in March 1991); Executive Vice President, Questar (February 1996); Director,
(October 1996); Director, QMR (May 1991), all Market Resources subsidiaries (various times
beginning in June 1989); Chairman, QET (August 1998).
D. N. Rose 57 President and Chief Executive Officer, Questar Gas (October 1984), Questar Pipeline (March
1997), QRS (December 1996), QES (January 1999); Executive Vice President, Questar (February
</Table>
-42-
<Page>
<Table>
<Caption>
1996); Director (May 1984); Director, Questar Gas (May 1984), Questar Pipeline (May 1996),
QRS (December 1996), and QES (January 1999).
Charles B. Stanley 43 Executive Vice President and Chief Operating Officer, QMR and QMR subsidiaries (February
2002); Senior Vice President, Questar (February 2002); President and Chief Executive Officer
and Director, Coastal Gas International Co. (1995 - 2000); President and Chief Executive
Officer of El Paso Oil and Gas Canada, Inc. (2000 - January 2002).
S. E. Parks 50 Senior Vice President (March 2001); Vice President ( February 1990 to March 2001); Treasurer
and Chief Financial Officer, Questar and all affiliates except QET (February 1996);
Treasurer, Questar and affiliates except QET at various dates beginning in May 1984);
Director, Questar E&P (May 1996) and Consonus (October 1999).
Connie C. Holbrook 55 Senior Vice President (March 2001); Vice President (October 1984 to March 2001); Corporate
Secretary (October 1984); General Counsel (April 1999); Corporate Secretary, Questar Gas and
other affiliates except QET (at various dates beginning in March 1982); Director, Consonus
(October 1999).
Glenn H. Robinson 51 President and Chief Executive Officer and Director, Questar InfoComm (August 2000); Vice
President and Chief Information Officer (August 2000); Vice President and Controller, QRS
(January 1999 to August 2000), Questar Gas (April 1991 to August 2000), and Questar Pipeline
(September 1996 to August 2000); Director, Consonus (May 2001).
Brent L. Adamson 51 Vice President, Ethics, Compliance and Audit (March 2002); Director, Audit (August 1982 to
March 2002); Compliance Officer (March 1995 to March 2002).
</Table>
There is no "family relationship" between any of the listed officers or
between any of them and the Company's directors. The executive officers serve at
the pleasure of the Board of Directors. There is no arrangement or understanding
under which the officers were selected. Information concerning compliance with
Section 16(a) of the Securities and Exchange Act of 1934, as amended, is
presented in the Company's definitive Proxy Statement under the section entitled
"Section 16(a) Compliance" and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information requested in this item is presented in Questar's
definitive Proxy Statement for the Company's 2002 annual meeting, under the
sections entitled "Executive Compensation" and
-43-
<Page>
"Election of Directors" and is incorporated herein by reference. The sections of
the Proxy Statement labeled "Committee Report on Executive Compensation" and
"Cumulative Total Shareholder Return" are expressly not incorporated into this
document.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information requested in this item for certain beneficial owners is
presented in Questar's definitive Proxy Statement for the Company's 2002 annual
meeting under the section entitled "Security Ownership, Principal Holders" and
is incorporated herein by reference. Similar information concerning the
securities ownership of directors and executive officers is presented in the
definitive Proxy Statement for the Company's 2002 annual meeting under the
section entitled "Security Ownership, Directors and Executive Officers" and is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information requested in this item for related transactions
involving the Company's directors and executive officers is presented in the
definitive Proxy Statement for the Questar's 2002 annual meeting under the
section entitled "Election of Directors."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)(1)(2) Financial Statements and Financial Statement Schedules.
The financial statements and schedule identified in the List of Financial
Statements are filed as part of this report.
(a)(3) Exhibits. The following is a list of exhibits required to be
filed as a part of this report in Item 14(c).
<Table>
<Caption>
Exhibit No. Description
- ----------- -----------
2.* Plan and Agreement of Merger dated as of December 16, 1986, by and among the Company, Questar Systems
Corporation, and Universal Resources Corporation. (Exhibit No. (2) to Current Report on Form 8-K dated
December 16, 1986.)
3.1.* Restated Articles of Incorporation as amended effective May 19, 1998. (Exhibit No. 3.1. to Form 10-Q Report
for Quarter ended June 30, 1998.)
3.2.* Bylaws (as amended effective October 25, 2001). (Exhibit No. 3.1. to Form 10_Q Report for Quarter ended
September 30, 2001.)
</Table>
-44-
<Page>
<Table>
4.1.*(1) Rights Agreement dated as of February 13, 1996, between the Company and Chemical Mellon Shareholder Services
L.L.C. pertaining to the Company's Shareholder Rights Plan. (Exhibit No. 4. to Current Report on Form 8-K
dated February 13, 1996.)
4.2.* Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No. 4. to Current Report on Form 8-K dated
February 8, 2000.)
10.1.* Stipulation and Agreement, dated October 14, 1981, executed by Mountain Fuel; Wexpro; the Utah Department of
Business Regulations, Division of Public Utilities; the Utah Committee of Consumer Services; and the staff of
the Public Service Commission of Wyoming. (Exhibit No. 10(a) to Mountain Fuel Supply Company's Form 10-K
Annual Report for 1981.)
10.2.*(2) Questar Corporation Annual Management Incentive Plan, as amended and restated effective February 13, 2001.
(Exhibit No. 10.2. to Form 10-K Annual Report for 2000.)
10.3.*(2) Questar Corporation Executive Incentive Retirement Plan, as amended and restated effective May 19, 1998.
(Exhibit No. 10.2. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.4.*(2) Questar Corporation Long-Term Stock Incentive Plan, as amended and restated effective March 1, 2001. (Exhibit
No. 10.4. to Form 10-K Annual Report for 2000.)
10.5.*(2) Questar Corporation Executive Severance Compensation Plan, as amended and restated effective May 19, 1998.
(Exhibit No. 10.3. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.6.*(2) Questar Corporation Deferred Compensation Plan for Directors, as amended and restated effective October 26,
2000. (Exhibit No. 10.6. to Form 10-K Annual Report for 2000.)
10.7.*(2) Questar Corporation Supplemental Executive Retirement Plan, as amended and restated effective June 1, 1998.
(Exhibit No. 10.6. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.8.*(2) Questar Corporation Stock Option Plan for Directors, as amended and restated effective October 29, 1998.
(Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended September 30, 1998.)
10.9.*(2) Form of Individual Indemnification Agreement dated February 9, 1993 between Questar Corporation and Directors.
(Exhibit No. 10.11. to Form 10-K Annual Report for 1992.)
</Table>
-45-
<Page>
<Table>
10.10.(2) Questar Corporation Deferred Share Plan, as amended and restated effective January 1, 2002.
10.11.(2) Questar Corporation Deferred Compensation Plan, as amended and restated effective January 1, 2002.
10.12.*(2) Questar Corporation Directors' Stock Plan as approved May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report
for Quarter ended June 30, 1996.)
10.13. Questar Corporation Deferred Share Make-Up Plan as amended and restated effective January 1, 2002.
10.14.*(2) Questar Corporation Special Situation Retirement Plan. (Exhibit No. 10.10. to Form 10-Q Report for Quarter
Ended June 30, 1998.)
10.15.*(2) Employment Agreement between the Company and Keith O. Rattie effective February 1, 2001. (Exhibit No. 10.15.
to Form 10-K Annual Report for 2000.)
10.16.(2) Employment Agreement between the Company and Charles B. Stanley effective January 31, 2002 and First Amendment
to such Agreement.
21. Subsidiary Information.
23. Consent of Independent Auditors.
24. Power of Attorney.
99.1. Undertakings for Registration Statements on Form S-3 (No. 33-48168) and on Form S-8 (Nos. 33-4436, 33-15149,
33-40800, 33-40801, 33-48169, 333-04913, and 333-04951).
</Table>
- ----------
*Exhibits so marked have been filed with the Securities and Exchange
Commission as part of the indicated filing and are incorporated herein by
reference.
(1) The name of the Rights Agent has been changed to U. S. Bank
National Association.
(2) Exhibit so marked is management contract or compensation plan or
arrangement.
(b) The Company did not file any Current Reports on Form 8-K during
the last quarter of 2001.
-46-
<Page>
ANNUAL REPORT ON FORM 10-K
ITEM 8, ITEM 14(a)(1) and (2), and (d)
LIST OF FINANCIAL STATEMENTS
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
YEAR ENDED DECEMBER 31, 2001
QUESTAR CORPORATION
SALT LAKE CITY, UTAH
FORM 10-K -- ITEM 14 (a)(1) AND (2)
QUESTAR CORPORATION AND SUBSIDIARIES
LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
The following financial statements of Questar Corporation and subsidiaries are
included in Item 8:
Consolidated statements of income--Years ended December 31, 2001, 2000 and
1999
Consolidated balance sheets--December 31, 2001 and 2000
Consolidated statements of common shareholder's equity--Years ended
December 31, 2001, 2000 and 1999
Consolidated statements of cash flows--Years ended December 31, 2001,
2000 and 1999
Notes to consolidated financial statements
The following financial statement schedule is included in Item 8:
Schedule: Valuation and Qualifying Accounts
All other financial statement schedules, for which provision is made in the
applicable accounting regulations of the Securities and Exchange Commission, are
not required under the related instructions or are inapplicable and therefore
have been omitted.
-47-
<Page>
Report of Independent Auditors
Shareholders and Board of Directors
Questar Corporation
We have audited the accompanying consolidated balance sheets of Questar
Corporation and subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of income and common shareholders' equity and cash flows
for each of the three years in the period ended December 31, 2001. Our audits
also included the financial statement schedule listed in the Index at Item
14(a). These financial statements and schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Questar
Corporation and subsidiaries at December 31, 2001 and 2000, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States. Also in our opinion, the related
financial statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
As discussed in Notes 1 and 6 to the financial statements, effective January 1,
2001, Questar Corporation and subsidiaries adopted Statement of Financial
Accounting Standards No. 133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING
ACTIVITIES.
/s/Ernst & Young LLP
-----------------------------------
Ernst & Young LLP
Salt Lake City, Utah
February 8, 2002
-48-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
-------------------------------------------------
(In Thousands, Except Per Share Amounts)
REVENUES $1,439,350 $1,266,153 $924,219
OPERATING EXPENSES
Cost of natural gas and other products sold 675,011 562,229 352,554
Operating and maintenance 270,355 251,477 221,082
Depreciation, depletion and amortization 151,735 142,491 132,164
Exploration 6,986 7,917 5,321
Abandonment and impairment of oil
and gas properties 5,171 3,418 7,535
Production and other taxes 55,985 50,654 32,724
------------------------------------------------
TOTAL OPERATING EXPENSES 1,165,243 1,018,186 751,380
------------------------------------------------
OPERATING INCOME 274,107 247,967 172,839
INTEREST AND OTHER INCOME 37,023 39,463 78,700
OPERATIONS OF UNCONSOLIDATED
AFFILIATES
Income (loss) 159 3,996 (4,356)
Write-down of investment in partnership (49,700)
------------------------------------------------
159 3,996 (54,056)
DEBT EXPENSE (64,833) (63,510) (53,944)
------------------------------------------------
INCOME BEFORE INCOME TAXES 246,456 227,916 143,539
INCOME TAXES 88,270 78,439 46,687
------------------------------------------------
NET INCOME $ 158,186 $ 149,477 $ 96,852
================================================
EARNINGS PER COMMON SHARE
Basic $ 1.95 $ 1.86 $ 1.17
Diluted $ 1.94 $ 1.85 $ 1.17
Average common shares outstanding
Basic 81,097 80,412 82,547
Diluted 81,658 80,915 82,676
</Table>
See notes to consolidated financial statements
-49-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
December 31,
2001 2000
------------------------------------
(In Thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 11,300 $ 9,416
Accounts receivable, net 151,844 269,254
Unbilled gas accounts receivable 53,613 45,293
Federal income taxes recoverable 3,593 9,694
Hedging contracts 50,270
Inventories, at lower of average cost or market
Gas and oil storage 37,055 30,062
Materials and supplies 12,073 10,472
Purchased-gas adjustments 8,296 35,565
Prepaid expenses and other 16,136 9,189
------------------------------------
TOTAL CURRENT ASSETS 344,180 418,945
PROPERTY, PLANT AND EQUIPMENT
Questar Market Resources 1,979,164 1,400,159
Questar Regulated Services
Gas distribution 1,144,455 1,067,362
Gas transmission 881,248 731,246
Other 9,519 5,764
Corporate and Other Operations 75,021 82,603
------------------------------------
4,089,407 3,287,134
LESS ACCUMULATED DEPRECIATION,
DEPLETION AND AMORTIZATION
Questar Market Resources 731,330 662,923
Questar Regulated Services
Gas distribution 489,583 447,496
Gas transmission 256,755 243,006
Other 4,586 3,073
Corporate and Other Operations 42,055 43,661
------------------------------------
1,524,309 1,400,159
------------------------------------
NET PROPERTY, PLANT AND EQUIPMENT 2,565,098 1,886,975
INVESTMENT IN UNCONSOLIDATED
AFFILIATES 144,928 34,505
SECURITIES AVAILABLE FOR SALE 13,623 33,019
OTHER ASSETS
Goodwill, net 90,927 20,514
Regulatory assets 37,984 37,646
Other noncurrent assets 38,971 40,423
------------------------------------
TOTAL OTHER ASSETS 167,882 98,583
------------------------------------
$3,235,711 $2,472,027
====================================
</Table>
-50-
<Page>
LIABILITIES AND SHAREHOLDERS' EQUITY
<Table>
<Caption>
December 31,
2001 2000
-------------------------------------
(In Thousands)
CURRENT LIABILITIES
Short-term debt $ 530,246 $ 209,139
Accounts payable and accrued expenses
Accounts and other payables 199,150 273,884
Production and other taxes 33,694 30,718
Deferred income taxes 3,153 13,515
Interest 13,193 7,300
------------------------------------
Total accounts payable and accrued expenses 249,190 325,417
Current portion of long-term debt 1,705 8
------------------------------------
TOTAL CURRENT LIABILITIES 781,141 534,564
LONG-TERM DEBT 997,423 714,537
DEFERRED INCOME TAXES 324,309 213,136
DEFERRED INVESTMENT TAX CREDITS 4,966 5,262
OTHER LONG-TERM LIABILITIES 27,286 33,680
MINORITY INTEREST 19,805 18,216
COMMITMENTS AND CONTINGENCIES - Note 8
COMMON SHAREHOLDERS' EQUITY
Common stock - without par value; 350,000,000
shares authorized; 81,523,407 outstanding at
December 31, 2001 and 80,818,274 outstanding
at December 31, 2000 282,297 268,630
Retained earnings 772,408 671,415
Cumulative other comprehensive income 26,076 12,587
------------------------------------
TOTAL COMMON SHAREHOLDERS' EQUITY 1,080,781 952,632
------------------------------------
$3,235,711 $2,472,027
====================================
</Table>
See notes to consolidated financial statements
-51-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<Table>
<Caption>
Cumulative
Common Stock Note Other Compre-
--------------------------- Retained Receivable Comprehensive hensive
Shares Amount Earnings from ESOP Income Income
-------------------------------------------------------------------------------
(Dollars in Thousands)
BALANCES AT JANUARY 1, 1999 82,632,078 $298,888 $535,460 $(3,955) $18,359
Issuance of common stock 488,302 8,124
Purchase of common stock (1,701,527) (28,575)
1999 net income 96,852 $ 96,852
Payment of common stock dividends
of $.67 per share (55,328)
Income tax benefit of dividends paid to ESOP 38
Collection of note receivable from ESOP 3,955
Other comprehensive income
Unrealized gain on securities available for sale,
net of income taxes of $13,193 21,303 21,303
Foreign currency translation adjustment,
net of income taxes of $327 (605) (605)
------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 1999 81,418,853 278,437 577,022 - 39,057 $117,550
=========
Issuance of common stock 958,232 11,764
Purchase of common stock (1,558,811) (25,543)
2000 net income 149,477 $149,477
Payment of common stock dividends
of $.685 per share (55,084)
Income tax benefit associated with exercise of
nonqualified options and premature dispositions 3,972
Other comprehensive income
Unrealized loss on securities available for sale,
net of income taxes of $16,767 (25,453) (25,453)
Foreign currency translation adjustment,
net of income taxes of $949 (1,017) (1,017)
------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 2000 80,818,274 268,630 671,415 - 12,587 $123,007
=========
Issuance of common stock 1,148,080 23,316
Purchase of common stock (442,947) (12,488)
2001 net income 158,186 $158,186
Payment of common stock dividends
of $.705 per share (57,193)
Income tax benefit associated with exercise of
nonqualified options and premature dispositions 2,839
Other comprehensive income
Cumulative effect of accounting change for
energy hedges, net income taxes of $41,624 (79,376) (79,376)
Change in unrealized gain on cash flow hedges
net of income taxes of $57,048 105,295 105,295
Unrealized loss on securities available for sale,
net of income taxes of $6,565 (10,595) (10,595)
Unrealized loss on interest rate swaps,
net of income taxes of $235 (392) (392)
Foreign currency translation adjustment,
net of income taxes of $1,304 (1,443) (1,443)
------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 2001 81,523,407 $282,297 $772,408 $ - $26,076 $171,675
==============================================================================
</Table>
See notes to consolidated financial statements
-52-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
-----------------------------------
(In Thousands)
OPERATING ACTIVITIES
Net income $ 158,186 $ 149,477 $ 96,852
Adjustments to reconcile net income to net cash
provided from operating activities
Depreciation, depletion and amortization 159,042 148,293 139,124
Deferred income taxes and investment tax credits 33,699 47,355 (1,087)
Write-down of investment in partnership 49,700
Abandonment and impairment of oil and gas properties 5,171 3,418 7,535
Write-down of securities available for sale 1,473
(Income) loss from unconsolidated affiliates,
net of cash distributions 253 (899) 7,671
Net gains from sales of properties and securities (21,765) (24,739) (66,962)
-----------------------------------
336,059 322,905 232,833
Changes in operating assets and liabilities
Accounts receivable 119,344 (136,700) (1,004)
Inventories (8,434) (2,892) 252
Hedging contracts (10,886)
Prepaid expenses and other (2,785) 2,077 615
Accounts payable and accrued expenses (90,441) 144,190 (41,549)
Federal income taxes 6,196 (27,068) 8,684
Purchased-gas adjustments 27,246 (35,133) 1,635
Other assets 3,436 (17,144) 3,446
Other liabilities (7,061) 1,832 2,419
-----------------------------------
NET CASH PROVIDED FROM OPERATING ACTIVITIES 372,674 252,067 207,331
INVESTING ACTIVITIES
Capital expenditures
Purchase of property, plant and equipment (870,652) (305,818) (215,814)
Other investments (113,434) (9,324) (46,169)
-----------------------------------
Total capital expenditures (984,086) (315,142) (261,983)
Proceeds from disposition of property, plant
and equipment 47,422 2,726 45,721
Proceeds from sales of securities 1,612 46,814 75,126
-----------------------------------
NET CASH USED IN INVESTING ACTIVITIES (935,052) (265,602) (141,136)
FINANCING ACTIVITIES
Issuance of common stock 26,155 15,736 8,124
Purchase of Questar common stock (12,488) (25,543) (28,575)
Issuance of long-term debt 645,000 61,725 317,000
Repayment of long-term debt (357,799) (80,075) (206,996)
Increase (decrease) in short-term loans 321,107 64,581 (76,985)
Cash held in escrow (1,010) 31,340 (36,727)
Other financing 716 2,955 3,993
Payment of dividends (57,193) (55,084) (55,328)
-----------------------------------
NET CASH PROVIDED FROM (USED IN)
FINANCING ACTIVITIES 564,488 15,635 (75,494)
Foreign currency translation adjustment (226) (975) 101
-----------------------------------
CHANGE IN CASH AND CASH EQUIVALENTS 1,884 1,125 (9,198)
BEGINNING CASH AND CASH EQUIVALENTS 9,416 8,291 17,489
-----------------------------------
ENDING CASH AND CASH EQUIVALENTS $ 11,300 $ 9,416 $ 8,291
===================================
</Table>
See notes to consolidated financial statements
-53-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Accounting Policies
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements contain the
accounts of Questar Corporation and subsidiaries (Questar or the Company).
Questar is a diversified natural gas company with two principal lines of
business: nonregulated and regulated. The Company's nonregulated activities of
gas and oil exploration, development and production, gas gathering and
processing, wholesale-energy marketing and a private storage facility are
conducted by Questar Market Resources, Inc. and subsidiaries (QMR or Market
Resources). The Company's regulated activities of natural gas distribution,
interstate transmission and storage operations are conducted by Questar
Regulated Services Co. and subsidiaries (QRS or Regulated Services). Natural
gas-distribution activities are conducted by Questar Gas. Questar Pipeline
provides natural gas transmission and storage. Questar Transportation Services,
a subsidiary of Questar Pipeline, operates a processing plant that removes
carbon dioxide from a portion of the pipeline. Regulated Services also includes
Questar Energy Services, which markets unregulated products and services.
Corporate and Other Operations include information-technology, telecommunication
services and corporate activities. All significant intercompany accounts and
transactions have been eliminated in consolidation.
INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Questar uses the equity method to
account for investments in affiliates in which it does not have control. The
principal affiliates are: Overthrust Pipeline Co., TransColorado Gas
Transmission Co., Canyon Creek Compression Co., Blacks Fork Gas Processing Co.
and Rendezvous Gas Services, LLC. Generally, the Company's investment in these
affiliates equals the underlying equity in net assets, except for TransColorado
where the investment was written down in 1999. The Company experienced an
other-than-temporary decline in its partnership investment in TransColorado
caused by low volumes resulting from unfavorable regional transportation
economics.
REGULATION: Questar Gas is regulated by the Public Service Commission of Utah
(PSCU) and the Public Service Commission of Wyoming (PSCW). The Idaho Public
Utilities Commission has deferred to the PSCU for rate oversight of Questar Gas'
operations in a small area of southeastern Idaho. Questar Pipeline is regulated
by the Federal Energy Regulatory Commission (FERC). Market Resources, through
its investment in Clear Creek Storage Company, LLC, operates a gas storage
facility that is under the jurisdiction of the FERC. These regulatory agencies
establish rates for the storage, transportation and sale of natural gas. The
regulatory agencies also regulate, among other things, the extension and
enlargement or abandonment of jurisdictional natural gas facilities. Regulation
is intended to permit the recovery, through rates, of the cost of service,
including a return on investment.
The financial statements of rate-regulated businesses are presented in
accordance with regulatory requirements. Methods of allocating costs to time
periods, in order to match revenues and expenses, may differ from those of other
businesses because of cost-allocation methods used in establishing rates.
USE OF ESTIMATES: The preparation of financial statements in conformity with
accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the amounts of assets
and liabilities and disclosure of contingent liabilities reported in the
financial statements and accompanying notes. Actual results could differ from
those estimates.
REVENUE RECOGNITION: Revenues are recognized in the period that services are
provided or products are delivered. Questar Gas records gas-distribution
revenues for gas delivered to residential and commercial customers but not
billed at the end of the accounting period. Rate-regulated companies
periodically collect revenues subject to possible refunds pending final orders
from regulatory agencies. These companies establish appropriate reserves for
revenues collected subject to refund. The Company's exploration and production
operations use the sales method of accounting for gas revenues, whereby revenue
is recognized on all gas sold to purchasers. A liability is recorded to
-54-
<Page>
the extent that the Company has sold gas in excess of its share of remaining
reserves in an underlying property. The Company's net gas imbalances at December
31, 2001 and 2000 were not significant.
PURCHASED-GAS ADJUSTMENTS: Questar Gas accounts for purchased-gas costs in
accordance with procedures authorized by the PSCU and PSCW under which
purchased-gas costs that are different from those provided for in present rates
are accumulated and recovered or credited through future rate changes. Questar
Gas will continue to pursue hedging activities to mitigate energy-price
fluctuations for gas-distribution customers. The PSCU has agreed that the
benefits and the costs of hedging are to be included in the purchased-gas
adjustment account. The stipulation allows Questar Gas to record mark-to-market
adjustments for hedging contracts in the purchased-gas adjustment account. The
PSCW also allows the inclusion of hedging activities in the purchase-gas
adjustment account.
OTHER REGULATORY ASSETS AND LIABILITIES: Gains and losses on the reacquisition
of debt by rate-regulated affiliates are deferred and amortized as debt expense
over the would-be remaining life of the retired debt or the life of the
replacement debt in order to match regulatory treatment. The cost of the early
retirement windows offered to employees of rate-regulated subsidiaries is
capitalized and amortized over a five-year period in accordance with regulatory
treatment. Rate-regulated operations record cumulative increases in deferred
taxes as income taxes recoverable from customers.
CASH AND CASH EQUIVALENTS: Cash equivalents consist principally of repurchase
agreements with maturities of three months or less. In almost all cases, the
repurchase agreements are highly liquid investments in overnight securities made
through commercial bank accounts that result in available funds the next
business day.
SECURITIES AVAILABLE FOR SALE: The value of securities available for sale
approximates fair value at the balance sheet date based on published share
prices. Using market value at the balance sheet date, the Company records
unrealized gains or losses, net of income taxes, as a separate component of
other comprehensive income in shareholders' equity. Gains or losses resulting
from the sale of securities are included in the determination of income as
incurred.
PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment is stated at cost.
On July 1, 2001, Questar elected to change its accounting method for gas and oil
properties from the full cost method to the successful efforts method. As a
result, on January 9, 2002, the Company filed an amended Form 10-K for the year
ended December 31, 2000 to retroactively restate financial statements to reflect
this change in accounting method. Previously reported earnings decreased $7.2
million ($.09 per share) and $2.0 million ($.03 per share) for the years ended
December 31, 2000 and 1999, respectively.
GAS AND OIL PROPERTIES
Under the successful efforts method of accounting, the Company capitalizes the
costs of acquiring leaseholds, drilling development wells, drilling successful
exploratory wells, and purchasing related support equipment and facilities. The
costs of unsuccessful exploratory wells are charged to expense when it is
determined that such wells have not located proved reserves. Unproved leaseholds
costs are periodically reviewed for impairment. Costs related to impaired
prospects are charged to expense. Costs of geological and geophysical studies
and other exploratory activities are expensed as incurred. Costs associated with
production and general corporate activities are expensed in the period incurred.
The Company recognizes gain or loss on the sale of properties on a field basis.
Capitalized proved leasehold costs are depleted on the unit-of-production method
based on proved reserves on a field basis. All other capitalized costs
associated with gas and oil properties are depreciated on the unit-of-production
method based on proved developed reserves on a field basis. Costs of future site
restoration, dismantlement, and abandonment of producing properties are
considered part of depreciation, depletion and amortization expense for tangible
equipment by assuming no salvage value in the calculation of the unit-of-
production rate.
-55-
<Page>
COST-OF-SERVICE GAS AND OIL OPERATIONS
As ordered by the PSCU, the successful efforts method of accounting is utilized
with respect to costs associated with certain "cost of service" gas and oil
properties managed and developed by Wexpro and regulated for ratemaking
purposes. Cost-of-service gas and oil properties are those properties for which
the operations and return on investment are regulated by the Wexpro settlement
agreement (see Note 11). In accordance with the settlement agreement, production
from the gas properties operated by Wexpro is delivered to Questar Gas at
Wexpro's cost of providing this service. That cost includes a return on Wexpro's
investment. Oil produced from the cost-of-service properties is sold at market
prices. Proceeds are credited, pursuant to the terms of the settlement
agreement, allowing Questar Gas to share in the proceeds for the purpose of
reducing natural gas rates.
Capitalized costs are depreciated on an individual field basis using the
unit-of-production method based upon proved developed gas and oil reserves
attributable to the field. Costs of future site restoration, dismantlement, and
abandonment for producing properties are considered as part of depreciation and
amortization expense for tangible equipment by assuming no salvage value in the
calculation of the unit-of-production rate.
<Table>
<Caption>
2001 2000
-----------------------
(In Thousands)
PROPERTY, PLANT AND EQUIPMENT
Gas and oil properties - successful efforts accounting
Proved properties $1,175,432 $ 845,485
Unproved properties, not being depleted 176,141 55,608
Support equipment and facilities 11,414 13,179
-----------------------
1,362,987 914,272
Cost-of-service gas and oil properties -
successful efforts accounting 405,783 348,403
Gathering, processing and marketing 210,394 137,484
-----------------------
$1,979,164 $1,400,159
=======================
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Gas and oil properties - successful efforts
accounting $ 462,143 $ 411,506
Cost-of-service gas and oil properties -
successful efforts accounting 207,410 193,029
Gathering, processing and marketing 61,777 58,388
-----------------------
$ 731,330 $ 662,923
=======================
</Table>
Average depreciation, depletion and amortization rates used in the 12 months
ended December 31 were as follows:
<Table>
<Caption>
2001 2000 1999
-------------------------------------
Questar Market Resources
Gas and oil properties, per Mcf equivalent
U.S $ 0.79 $ 0.73 $ 0.72
Canada (in U.S. dollars) 1.10 1.12 0.63
Combined U.S. and Canada 0.83 0.78 0.71
Cost-of-service gas and oil properties, per Mcfe 0.49 0.44 0.42
</Table>
For the remaining Company properties, the provision for depreciation, depletion
and amortization is based upon rates that will systematically charge the costs
of assets against income over the estimated useful lives of those assets. The
investment in natural gas distribution, transmission, storage, gathering and
processing property, plant and equipment, is charged to expense using the
straight-line method. The costs of gas wells and related production facilities
are charged to expense using the unit-of-production method.
-56-
<Page>
Average depreciation, depletion and amortization rates used in the 12 months
ended December 31 were as follows:
<Table>
<Caption>
2001 2000 1999
-------------------------------
Questar Regulated Services
Natural gas distribution
Distribution plant 3.8% 4.0% 4.2%
Gas wells, per Mcf $ 0.14 $ 0.15 $ 0.15
Natural gas transmission, processing and storage 2.9% 3.2% 3.4%
</Table>
TEST FOR IMPAIRMENT OF LONG-LIVED ASSETS
Gas and oil properties are evaluated by field for potential impairment; other
properties are evaluated on a specific asset basis or in groups of similar
assets, as applicable. An impairment is indicated when a triggering event occurs
and the estimated undiscounted future net cash flows of an evaluated asset are
less than its carrying value.
GOODWILL: Goodwill acquired before July 1, 2001 was amortized on the
straight-line method principally over 10 years. Goodwill amortization expense
was $2.2 million in 2001 and $1.7 million in 2000. The accumulated amortization
balance was $3.9 million at December 31, 2001. Goodwill accounting rules changed
July 1 2001. Refer to the "New Accounting Standards" discussion.
CAPITALIZED INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION: Questar's
regulated subsidiaries capitalize the cost of capital employed during the
construction period of plant and equipment in accordance with guidelines from
regulators. Capitalized financing costs, called allowance for funds used during
construction (AFUDC), consist of debt and equity portions. The debt portion of
AFUDC is recorded as a reduction of interest expense and the equity portion is
recorded in other income. The Company's nonregulated subsidiaries capitalize
interest costs during construction of assets when it is applicable. Under
provisions of the Wexpro settlement agreement, the Company capitalizes AFUDC on
cost-of-service construction projects and records the amount in other income.
Debt expense was reduced by $4.1 million in 2001, $4.2 million in 2000 and $3.0
million in 1999. AFUDC included in interest and other income amounted to $5.5
million in 2001, $4.5 million in 2000 and $2.0 million in 1999.
FOREIGN CURRENCY TRANSLATION: The Company conducts gas and oil exploration and
production activities in western Canada. The local currency, the Canadian
dollar, is the functional currency of the Company's foreign operations.
Translation from Canadian dollars to U. S. dollars is performed for balance
sheet accounts using the exchange rate in effect at the balance sheet date.
Revenue and expense accounts are translated using an average exchange rate.
Adjustments resulting from such translations are reported as a separate
component of other comprehensive income in shareholders' equity. Deferred income
taxes have been provided on translation adjustments because the earnings are not
considered to be permanently invested.
ENERGY-PRICE FINANCIAL INSTRUMENTS: The Company has established policies and
procedures for managing market risks through the use of commodity-based
derivative arrangements. Primary objectives of these hedging transactions are to
support the Company's earnings targets and to protect earnings from downward
moves in commodity prices. It is expected that there will be a high degree of
correlation between the changes in market value of hedging contracts and the
market price ultimately received on the hedged physical transactions. The timing
of production and the maturity of the hedge contracts are closely matched. Hedge
prices are established in the areas of Market Resources' production operations.
The Company settles most contracts in cash and recognizes the gains and losses
on hedge transactions during the same time period as the related physical
transactions. Cash flows from the hedge contracts are reported in the same
category as cash flows from the hedged assets. Contracts that do not have high
correlation with the related physical transactions are marked-to-market and
recognized in the current-period income.
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standard (SFAS) 133, as amended, "Accounting for Derivative Instruments and
Hedging Activities." Refer to the "Energy-Price Management" discussion in Note 6
- - Financial Instruments and Risk Management. SFAS 133 addresses the accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts. Under the standard,
-57-
<Page>
the Company is required to carry all derivative instruments in the balance sheet
at fair value. The accounting for changes in fair value, which result in gains
or losses, of a derivative instrument depends on whether such instrument has
been designated and qualifies as part of a hedging relationship and, if so,
depends on the reason for holding it. If certain conditions are met, the Company
may elect to designate a derivative instrument as a hedge of exposure to changes
in fair value, cash flows or foreign currencies. If the hedged exposure is a
fair-value exposure, the gain or loss on the derivative instrument is recognized
in earnings in the period of the change together with the offsetting loss or
gain from the change in fair value of the hedged item. If the hedged exposure is
a cash-flow exposure, the effective portion of the gain or loss on the
derivative instrument is reported initially as a component of other
comprehensive income in the shareholders' equity section of the balance sheet
and subsequently reclassified into earnings when the forecasted transaction
affects earnings. Any amount excluded from the assessment of hedge
effectiveness, as well as the ineffective portion of the gain or loss, is
reported in earnings immediately.
INTEREST-RATE FINANCIAL INSTRUMENTS: The Company may utilize interest-rate
hedges to swap fixed-rate interest payments for variable-rate interest payments.
The difference between the fixed interest-rate swap payment made and the
variable-rate swap payment is recorded as either an increase or decrease of
interest expense.
CREDIT RISK: The Company's primary market areas are the Rocky Mountain regions
of the United States and Canada and the Midcontinent region of the United
States. Exposure to credit risk may be impacted by the concentration of
customers in these regions due to changes in economic or other conditions.
Customers include individuals and numerous industries that may be affected
differently by changing conditions. Management believes that its credit-review
procedures, loss reserves, customer deposits and collection procedures have
adequately provided for usual and customary credit-related losses.
Commodity-based hedging arrangements also expose the Company to credit risk. The
Company monitors the creditworthiness of its counterparties, which generally are
major financial institutions. Loss reserves are periodically reviewed for
adequacy and may be established on a specific case basis. Bad debt expense
amounted to $8.6 million, $3.9 million and $3.1 million for the years ended
December 31, 2001, 2000 and 1999, respectively. The allowance for bad debt
expenses was $6.3 million and $3.5 million at December 31, 2001 and 2000,
respectively.
INCOME TAXES: Questar files income tax returns on a consolidated basis in
accordance with the Internal Revenue Code and associated regulations. Questar's
subsidiaries account for income taxes on a separate-return basis. Rate-
regulated operations record cumulative increases in deferred taxes as income
taxes recoverable from customers. Questar Gas and Questar Pipeline have adopted
procedures with their regulatory commissions to include under-provided deferred
taxes in customer rates on a systematic basis. Questar Gas and Questar Pipeline
use the deferral method to account for investment tax credits as required by
regulatory commissions.
EARNINGS PER SHARE: The Company presents basic and diluted earnings per share
(EPS) on the income statement. Basic EPS is computed by dividing net income
available to common shareholders by the weighted average number of common shares
outstanding during the accounting period. Diluted EPS includes the potential
increase in the number of outstanding shares that could result from exercising
stock options; which is the reason for the difference between the number of
basic and diluted average shares outstanding.
COMPREHENSIVE INCOME: Comprehensive income is the sum of net income as reported
in the Consolidated Statement of Income and other comprehensive income
transactions reported in the Consolidated Statement of Shareholders' Equity.
Other comprehensive income transactions result from changes in the market value
of securities available for sale, qualified energy derivatives and interest rate
derivatives, and changes in holding value resulting from foreign currency
translation adjustments. These transactions are not the culmination of the
earnings process, but result from periodically adjusting historical balances to
fair value. Income or loss is realized when the underlying energy product or
securities available for sale are sold. The balances of cumulative other
comprehensive income (loss), net of income taxes, at December 31, were as
follows:
-58-
<Page>
<Table>
<Caption>
2001 2000
---------------------
(In Thousands)
Unrealized gain on energy hedging transactions $ 25,919
Unrealized loss on interest rate swap (392)
Unrealized gain on securities available for sale 3,237 $ 13,832
Foreign currency translation adjustment (2,688) (1,245)
----------------------
Cumulative other comprehensive income $ 26,076 $ 12,587
=======================
</Table>
BUSINESS SEGMENTS: Questar's line-of-business disclosures are presented based on
the way senior management evaluates the performance of its business segments.
Certain intersegment sales include intercompany profit.
NEW ACCOUNTING STANDARDS: In June 2001, the Financial Accounting Standards Board
("FASB") issued SFAS 141, "Business Combinations," which addresses financial
accounting and reporting for business combinations. SFAS 141 is effective for
all business combinations initiated after June 30, 2001 and for all business
combinations accounted for under the pooling method initiated before but
completed after June 30, 2001. The Company applied the purchase method of
accounting when recording two acquisitions completed in the third quarter of
2001.
In June 2001, the FASB issued SFAS 142, "Goodwill and Other Intangible Assets,"
which addresses, among other things, the financial accounting and reporting for
goodwill subsequent to an acquisition. The new standard eliminates the
requirement to amortize acquired goodwill; instead, such goodwill shall be
reviewed at least yearly for impairment or sooner if a specific trigger occurs.
Goodwill acquired after July 1, 2001, is exempt from amortization. At December
31, 2001, the Company's balance of goodwill amounted to $91 million of which $73
million was acquired after July 1, 2001. The Company will adopt SFAS 142 as of
January 1, 2002 and has up to six months to perform an initial goodwill
impairment test. However, if impairment is indicated in the initial test, the
impairment must be recorded retroactive to January 1, 2002 as a cumulative
effect of a change in accounting method. Subsequent impairments will be charged
to operating results. An initial test under the new accounting rules indicates
that the Company could record an impairment charge of up to $18.2 million.
Intangible assets with indefinite lives are subject to a yearly impairment test
according to SFAS 142. As of December 31, 2001, the Company held about $592,000
of intangible asset with indefinite lives and no impairment was indicated in an
initial test.
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations," which addresses, among other things, the financial accounting and
reporting of the fair value of legal obligations associated with the retirement
of tangible long-lived assets. The new standard requires that retirement costs
be estimated at fair value, capitalized and depreciated over the life of the
assets. The new standard may affect the cost basis of gas and oil and
rate-regulated assets. SFAS 143 is effective for 2003. The Company has not
evaluated the impact of SFAS 143.
In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." The new standard addresses financial accounting
and reporting for the impairment or disposal of long-lived assets, specifically,
for a segment of a business accounted for as a discontinued operation and
modifies the provisions of SFAS 121. SFAS 144 is effective for 2002. The Company
has not evaluated the impact of SFAS 144.
RECLASSIFICATIONS: Certain reclassifications were made to the 2000 and 1999
financial statements to conform with the 2001 presentation.
-59-
<Page>
Note 2 - Acquisitions
Questar Market Resources acquired 100% of the common stock of Shenandoah Energy,
Inc. (SEI) on July 31, 2001 for $403 million in cash including assumed debt. SEI
was a privately held Denver-based exploration, production, gathering and
drilling company. QMR obtained an estimated 415 billion cubic feet equivalent of
proved oil and gas reserves, gas processing capacity of 100 MMcf per day, 90
miles of gathering lines, 114,000 acres of net undeveloped leasehold acreage and
four drilling rigs. SEI operations are located primarily in the Uintah Basin of
eastern Utah. The transaction was accounted for as a purchase business
combination in accordance with accounting principles generally accepted in the
United States. The purchase price in excess of the estimated fair value of the
assets was assigned to goodwill. The acquisition was initially financed through
bank borrowings.
Assets purchased and liabilities assumed were as follows:
<Table>
<Caption>
(In Thousands)
----------------
Current assets, net of cash acquired $ 17,332
Property, plant and equipment 401,054
Goodwill 66,823
Other assets 124
Current liabilities (24,328)
Other liabilities (8,410)
Deferred income taxes (54,364)
Other comprehensive loss 4,723
----------------
Purchase price, including acquisition costs $ 402,954
================
</Table>
The following unaudited pro forma consolidated results of operations assume the
acquisition occurred on January 1, 2000. The pro forma financial information
includes adjustments to:
Depreciation expense to reflect the new basis of SEI's fixed assets.
Interest expense to reflect financing costs of the acquisition.
Operating expenses to reflect the resignation of several SEI executives.
Exclude results of operations not purchased by QMR.
Income tax expense based on pro forma income before income taxes.
<Table>
<Caption>
Year Ended December 31,
2001 2000
----------------------------------------
(In Thousands, Except per share amounts)
Revenues $1,487,508 $1,309,972
Net income 155,604 139,909
Earnings per diluted share $ 1.91 $ 1.73
</Table>
Questar Gas completed the purchase of 100% of the stock of Utah Gas Service
Company and Wyoming Industrial Gas in exchange for 390,000 shares of Questar
common stock on July 12, 2001. As a result of the acquisition, Questar Gas will
add service to about 10,500 customers in Moab, Monticello and Vernal, Utah and
Kemmerer and Diamondville, Wyoming. The acquisition cost $10.9 million,
including $6 million of goodwill, and was accounted for as a purchase.
-60-
<Page>
Note 3 - Investment in Unconsolidated Affiliates
Questar, indirectly through subsidiaries, has interests in partnerships
accounted for on the equity basis. These entities are engaged primarily in
either the transportation or the gathering and processing of natural gas. As of
December 31, 2001, these affiliates did not have debt obligations with
third-party lenders. The principal partnerships and percentage ownership were as
follows: Overthrust Pipeline Co. (72%) and TransColorado Gas Transmission Co.
(50%) are engaged in the transportation of natural gas. Canyon Creek Compression
Co. (15%), Blacks Fork Gas Processing Co. (50%) and Rendezvous Gas Services LLC
(50%) are engaged in processing or gathering natural gas. Questar Pipeline
acquired an additional 18% of Overthrust Pipeline in January 2002 bringing its
ownership percentage to 90%.
Summarized results of the partnerships are listed below.
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
------------------------------------
(In Thousands)
TRANSPORTATION PARTNERSHIPS
Revenues $ 16,164 $ 11,770 $ 9,116
Operating loss (4,805) (7,949) (4,877)
Loss before income taxes (13,606) (20,764) (11,594)
Current assets, at end of period 13,315 4,927
Noncurrent assets, at end of period 301,431 315,825
Current liabilities, at end of period 5,146 208,402
Noncurrent liabilities, at end of period 13,662 9,940
Debt (included in current liabilities) 200,000
GAS GATHERING AND PROCESSING PARTNERSHIPS
Revenues $ 24,992 $ 27,574 $ 19,096
Operating income 2,830 5,811 2,922
Income before income taxes 3,105 6,184 2,803
Current assets, at end of period 21,000 14,232
Noncurrent assets, at end of period 38,862 26,941
Current liabilities, at end of period 3,893 3,940
Noncurrent liabilities, at end of period 2,529 946
</Table>
-61-
<Page>
Note 4 - Debt
Questar has short-term line-of-credit arrangements with several banks under
which it may borrow up to $250 million. These lines have interest rates
generally below the prime interest rate. Commercial paper borrowings with
initial maturities of less than one year are backed by the short-term
line-of-credit arrangements. The details of short-term debt are as follows:
<Table>
<Caption>
December 31,
2001 2000
----------------------
(In Thousands)
Commercial paper with variable interest rates $405,500 $181,100
Bank loans with variable interest rates 124,746 28,039
---------------------
$530,246 $209,139
=====================
Weighted average interest rate at December 31 2.27% 6.68%
</Table>
The details of long-term debt are as follows:
<Table>
<Caption>
December 31,
2001 2000
----------------------
(In Thousands)
Questar Market Resources
Revolving-credit loan due 2002 - 2007 with variable
interest rates (2.85% at December 31, 2001) $253,922 $244,377
7.5% Notes due 2011 150,000
Questar Regulated Services - Natural gas distribution
Medium-term notes 6.3% to 8.43%, due 2007
to 2024 285,000 225,000
Questar Regulated Services - Natural gas transmission
Medium-term notes 5.85% to 7.55%, due 2008
to 2018 310,400 130,400
9 3/8% debentures due 2021 85,000
9 7/8% debentures due 2020 30,000
Corporate and other 141 148
-----------------------
Total long-term debt outstanding 999,463 714,925
Less current portion 1,705 8
Less unamortized debt discount 335 380
----------------------
$997,423 $714,537
======================
</Table>
Maturities of long-term debt for the five years following December 31, 2001, in
thousands of dollars are as follows:
<Table>
2002 $ 1,705
2003 1,706
2004 221,707
2005 1,708
2006 1,710
</Table>
Cash paid for interest was $61.7 million in 2001, $66.8 million in 2000 and
$56.0 million in 1999.
Market Resources' revolving-credit loan contains covenants specifying a minimum
amount of net equity and a maximum ratio of debt to equity.
-62-
<Page>
QMR borrowed $415 million of which $280 million was in the form of a short-term
bridge loan. The bridge loan was subsequently refinanced with borrowings from
banks and a one-year callable commercial paper note in the amount of $220
million. The commercial paper note and bank borrowings were reduced with the
proceeds of a five-year, $200 million private placement note with a 7% interest
rate issued January 16, 2002. The terms of the private placement note required
that the notes be registered with the SEC. A registration statement was filed
February 22, 2002 that became effective March 4, 2002. The exchange notes are
expected to be issued in April 2002. In March 2001, QMR sold $150 million of
10-year notes with a 7.5% interest rate and used the proceeds to reduce debt.
During the third quarter of 2001, Questar Gas filed a Form S-3 with the
Securities and Exchange Commission to issue up to $100 million of medium-term
notes, series D, with maturities of nine months to 30 years. On October 9, 2001,
Questar Gas issued $60 million of 11-year notes with a 6.3% coupon rate.
On May 11, 2001, Questar Pipeline filed a Form S-3 with the Securities and
Exchange Commission to issue up to $250 million of medium-term notes, Series B,
with maturities of nine months to 30 years. On May 29, 2001, Questar Pipeline
issued $100 million of ten-year notes with a 7.09% coupon rate. On September 26,
Questar Pipeline issued $80 million of ten-year medium-term notes with a coupon
rate of 6.57%.
On March 30, 2001, Questar Pipeline redeemed the remaining $30 million of its 9
7/8% debentures. The redemption price was equal to 104.67% of the principal
amount plus interest from December 1, 2000. In addition, Questar Pipeline
redeemed all $85 million of its 9 3/8% debentures on June 25, 2001. The
redemption price was equal to 104.51% of the principal amount plus interest for
twenty-four days.
On October 12, 2001, Questar Pipeline borrowed $100 million. The proceeds were
used to repay debt, through a wholly owned subsidiary, Questar TransColorado,
Inc. (QTC), owed by TransColorado Gas Transmission Company (TransColorado).
Note 5 - Common Stock
Dividend Reinvestment and Stock Purchase Plan: The Dividend Reinvestment and
Stock Purchase Plan (Reinvestment Plan) allows parties interested in owning
Questar common stock to reinvest dividends or invest additional funds in common
stock. The Company can issue new shares or buy shares in the open market to meet
shareholders' purchase requests. The Reinvestment Plan issued total shares of
219,846, 322,062 and 371,985 in 2001, 2000 and 1999, respectively. At December
31, 2001, 1,700,915 shares were reserved for future issuance.
Employee Investment Plan: The Employee Investment Plan (Plan) allows eligible
employees to purchase shares of Questar Corporation common stock or other
investments through payroll deduction. The Company matches 80% of employees'
pretax purchases up to a maximum of 6% of their qualifying earnings. The
Company's expense equals its matching contribution. Questar's expense to the
Plan amounted to $5.3 million, $5.0 million and $4.7 million for the years ended
December 31, 2001, 2000 and 1999, respectively.
Stock Plan: The Company has a Long-term Stock Incentive Plan for officers,
directors and employees (Stock Plan). The current plan was amended March 1, 2001
to combine officers, directors and employees under one plan and reserve an
additional eight million shares. Shareholders approved the modification in May
2001. The option price equals the market price of the stock on the grant date.
Stock options for officers and employees have a ten-year life and vest in four
equal annual installments beginning six months after the grant date. Stock
options for nonemployee directors also have a ten-year life but vest completely
six months after grant. Nonemployee directors may choose to receive shares of
common stock instead of cash in payment for directors fees.
No compensation expense is recorded for stock options issued because the
exercise price equals the market price on the date of issue. If compensation
expense had been recorded, it would be based on an estimate of the fair value of
stock options granted and would reduce earnings per share by $.05 in 2001, $.03
in 2000 and $.02 in 1999. For
-63-
<Page>
purposes of the pro forma expense, the weighted average fair value of the
options was amortized over the vesting period. The pro forma estimates rely upon
subjective assumptions and the use of a mathematical model to estimate value,
and may not be representative of future results.
Transactions involving option shares in the Stock Plans are summarized as
follows:
<Table>
<Caption>
Weighted Average
Shares Price Range Exercise Price
-------------------------------------------------------
Balance at January 1, 1999 3,265,151 $ 9.81- $21.38 17.74
Granted 868,400 17.00 17.00
Cancelled (82,900) 9.81 - 21.38 17.94
Exercised (138,445) 9.81 - 16.81 14.44
-------------------------------------------------------
Balance at December 31, 1999 3,912,206 9.81 - 21.38 17.69
Granted 1,260,990 15.00 15.00
Cancelled (89,254) 13.69 - 21.38 17.19
Exercised (1,301,361) 9.81 - 21.38 15.99
-------------------------------------------------------
Balance at December 31, 2000 3,782,581 $ 9.81 -$21.38 $17.38
Granted 1,085,500 27.42 - 28.10 28.04
Cancelled (13,320) 15.00 - 21.38 16.02
Exercised (709,215) 9.81 - 21.38 17.10
-------------------------------------------------------
Balance at December 31, 2001 4,145,546 $ 9.81 -$28.10 $20.22
=======================================================
Exercisable at December 31, 2001 2,651,576 $19.23
Available for future grant at
December 31, 2001 8,697,201
</Table>
The stock options at December 31, 2001 had a weighted average remaining life of
7.3 years. The fair value of the stock options was determined on the grant date
using the Black-Scholes option-valuation model. The calculated fair value of
options granted and major assumptions used in the model at the date of grant
were as follows:
<Table>
<Caption>
2001 2000 1999
---------------------------------
Fair value of options at grant date $8.90 $3.38 $3.16
Risk-free interest rate 5.04% 6.79% 5.11%
Expected price volatility 30.7% 25.1% 20.6%
Expected dividend yield 2.52% 4.53% 3.88%
Expected life in years 7.3 7.0 7.2
</Table>
In addition to stock options, the Company issued restricted shares to officers
and employees as part of its payment of bonuses. In addition to issuing shares
in connection with bonuses, 21,000 shares was awarded in 2001 as part of
employment contract. Compensation expense is recorded when the bonus or award is
earned. The number of shares issued is determined using the market price on date
of grant. Recipients of restricted stock awards are entitled to full voting
rights and receipt of dividends. A portion of the restricted shares are reserved
for under the Stock Plan. Awards of restricted stock and vesting periods were as
follows:
<Table>
<Caption>
2001 2000 1999
------------------------------------
Vest in one year 28,913
Vest in equal installments over two years 30,897 46,053 16,919
Vest in equal installments over three years 21,000
------------------------------------
Total restricted shares awarded 80,810 46,053 16,919
====================================
Average market price per share at award date $ 24.07 $ 28.01 $ 15.00
</Table>
-64-
<Page>
Shareholder Rights: On February 13, 1996, Questar's Board of Directors declared
a stock-right dividend for each outstanding share of common stock. The stock
rights were issued March 25, 1996. The rights become exercisable if a person, as
defined, acquires 15% or more of the Company's common stock or announces an
offer for 15% or more of the common stock. Each right initially represents the
right to buy one share of the Company's common stock for $87.50. Once any person
acquires 15% or more of the Company's common stock, the rights are automatically
modified. Each right not owned by the 15% owner becomes exercisable for the
number of shares of Questar's stock that have a market value equal to two times
the exercise price of the right. This same result occurs if a 15% owner acquires
the Company through a reverse merger when Questar and its stock survive. If the
Company is involved in a merger or other business combination at any time after
the rights become exercisable, rightsholders will be entitled to buy shares of
common stock in the acquiring company having a market value equal to twice the
exercise price of each right. The rights may be redeemed by the Company at a
price of $.005 per right until 10 days after a person acquires 15% ownership of
the common stock. The rights expire March 25, 2006.
Note 6 - Financial Instruments and Risk Management
The carrying value and estimated fair values of the Company's financial
instruments were as follows:
<Table>
<Caption>
December 31, 2001 December 31, 2000
-----------------------------------------------------------------
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
-----------------------------------------------------------------
(In Thousands)
Financial assets
Cash and cash equivalents $ 11,300 $ 11,300 $ 9,416 $ 9,416
Financial liabilities
Short-term loans 530,246 530,246 209,139 209,139
Long-term debt 999,128 1,011,549 714,545 735,554
Energy-price hedging contracts 50,897 50,897 (98,000)
Interest-rate hedging swaps (627) (627)
</Table>
The Company used the following methods and assumptions in estimating fair
values:
CASH AND CASH EQUIVALENTS AND SHORT-TERM LOANS - the carrying amount
approximates fair value;
LONG-TERM DEBT - the carrying amount of variable-rate debt approximates fair
value. The fair value of fixed-rate debt is based on the
discounted present value of cash flows using the Company's current borrowing
rates;
ENERGY-PRICE HEDGING CONTRACTS - fair value of the contracts is based on
market prices as posted on the NYMEX from the last trading day of the year. The
average price of the oil contracts at December 31, 2001, was $25.47 per barrel
and was based on the average of fixed amounts in contracts which settle against
the NYMEX. All oil contracts relate to equity production where basis adjustments
would result in a net-to-the-well price of $24.45 per barrel. The average price
of the gas contracts at December 31, 2001 was $3.77 per MMBtu representing the
average of contracts with different terms including fixed, various "into the
pipe" postings and NYMEX references. Energy-price hedging contracts were in
place for equity gas production and gas-marketing transactions. Deducting
transportation and heat-value adjustments on the hedges of equity gas as of
December 31, 2001, would result in a price between $3.43 and $3.57 per Mcf,
net-back-to-the-well.
INTEREST-RATE SWAP - the mark-to-market valuation equals a discounted present
value of future cash flow using current market rates.
Fair value is calculated at a point in time and does not represent the amount
the Company would pay to retire the debt securities. In the case of energy-price
hedges, the fair value calculation does not consider the fair value of the
corresponding scheduled physical transactions (i.e., the correlation between the
index price and the price to be realized for the physical delivery of gas or oil
production).
-65-
<Page>
ENERGY-PRICE RISK MANAGEMENT
Market Resources held financial energy-price hedge contracts covering the
exposure for about 70.2 million dth of gas and 1.1 million barrels of oil at
December 31, 2001. A year earlier the contracts covered 50.5 million dth of
natural gas and 1.0 million barrels of oil. Hedging contracts exist for a
significant share of Questar-owned gas and oil production and for a portion of
gas-marketing transactions. The contracts at December 31, 2001, had terms
extending through December 2003. About 75% of those contracts, representing
$27.0 million settlement and will be reclassified from other comprehensive
income in the next 12 months.
On January 1, 2001, the Company adopted the accounting provisions of SFAS 133
and recorded a cumulative effect of this accounting change that decreased other
comprehensive income by $79.4 million (after-tax). The Company structured a
majority of its energy-price derivative instruments as cash flow hedges and as a
result of adopting SFAS 133 recorded a $121 million hedging liability for
derivative instruments. By the end of 2001, the Company's hedging contracts were
on a net basis, in-the-money. The results of hedging activities amounted to a
$50.9 million current asset. Settlement of contracts in 2001 had resulted in the
reclassification into income of $68 million ($44.6 million after-tax). The
remaining change of $103.9 million resulted from a decrease in prices of gas and
oil on futures markets. The offset to the hedging asset, net of income taxes,
was a $25.9 million unrealized gain on hedging activities recorded in other
comprehensive income in the shareholders' equity section of the balance sheet.
The ineffective portion of hedging transactions recognized in earnings was not
significant. The fair-value calculation does not consider changes in fair value
of the corresponding scheduled equity physical transactions.
INTEREST-RATE RISK MANAGEMENT
Effective October 2001, the Company hedged $100 million of variable-rate debt by
entering into a fixed-rate interest swap for one year. Due to declining interest
rates at the end of 2001, the mark-to-market adjustment of the interest rate
swap resulted in an unrealized loss of $627,000 and $67,000 of additional
interest expense.
SECURITIES AVAILABLE FOR SALE
Securities available for sale represent equity instruments traded on national
exchanges. The value of these investments is subject to day-to-day market
volatility. The Company owns 788,962 shares of common stock of Nextel
Communications and 182,696 shares of common stock of ParkerVision as of December
31, 2001, which are trading near cost basis. The SEC has determined that trading
below cost basis for two consecutive quarters constitutes an
other-than-temporary impairment that must be recognized in earnings. In 2001,
the Company recognized an other-than-temporary impairment of $1.5 million. The
Company reclassified $153,000, $41.8 million and $23.7 million in 2001, 2000 and
1999, respectively, from other comprehensive income and $59,000, $16 million and
$14.7 million in 2001, 2000 and 1999, respectively, from deferred income taxes.
CREDIT RISK MANAGEMENT
Management increased its bad debt reserves as it monitored the effect on
collections resulting from significantly higher energy prices in the first half
of 2001, an economic recession and an increase in bankruptcies filed in the
western United States.
FOREIGN CURRENCY RISK MANAGEMENT
The Company does not hedge the foreign currency exposure of its foreign
operation's net assets and long-term debt. Long-term debt held by the foreign
operation, amounting to $61.1 million (U.S.), is expected to be repaid from
future operations of the foreign company.
-66-
<Page>
Note 7 - Income Taxes
Details of Questar's income tax expenses and deferred income taxes are provided
in the following tables. The components of income taxes were as follows:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------
(In Thousands)
Federal
Current $ 48,757 $ 24,758 $ 43,326
Deferred 24,716 47,098 (2,745)
State
Current 5,641 4,067 6,602
Deferred 3,688 801 776
Deferred investment tax credits (401) (386) (387)
Foreign income taxes 5,869 2,101 (885)
---------------------------------
$ 88,270 $ 78,439 $ 46,687
=================================
</Table>
The difference between the statutory federal income tax rate and the Company's
effective income tax rate is explained as follows:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
---------------------------------
(In Percentages)
Federal income taxes at 35% 35.0 35.0 35.0
Increase (decrease) as a result of:
State income taxes, net of federal income
tax benefit 2.5 1.4 3.3
Non-conventional fuel credits (2.8) (2.8) (5.0)
Investment tax credits recognized (0.2) (0.2) (0.3)
Deferred taxes related to regulated assets
that were not provided in prior years 0.4 0.4 0.6
Tax benefits from dividends paid to ESOP (0.3)
Foreign income taxes 1.0 0.3 (0.1)
Other (0.1) 0.3 (0.7)
---------------------------------
Effective income tax rate 35.8 34.4 32.5
=================================
</Table>
-67-
<Page>
Significant components of the Company's deferred income taxes were as follows:
<Table>
<Caption>
December 31,
2001 2000
---------------------------
(In Thousands)
Deferred tax liabilities
Property, plant and equipment $350,497 $227,633
Debt reacquisition costs 5,987 4,418
Mark-to-market adjustments 2,005 8,568
Other 6,160 5,559
---------------------------
Total deferred tax liabilities 364,649 246,178
Deferred tax assets
Associated with write-down of investments 10,306 11,806
Deferred compensation 7,916 7,443
Ad valorem 5,106 3,277
Depletion and ITC carryforwards 1,885 1,995
Other 15,127 8,521
---------------------------
Total deferred tax assets 40,340 33,042
---------------------------
Deferred income taxes - noncurrent $324,309 $213,136
===========================
Deferred income taxes - current
Purchased -gas adjustment $ 3,153 $ 13,515
===========================
</Table>
Cash paid for income taxes was $43.8 million, $54.1 million and $35.2 million in
2001, 2000 and 1999, respectively.
Note 8 - Litigation and Commitments
KN TRANSCOLORADO, INC. V. QUESTAR CORPORATION
Questar TransColorado, Inc. (QTC) and its partner, KN TransColorado, Inc.,
(KNTC) in the TransColorado Gas Transmission Company (TransColorado) are
involved in a complex lawsuit that is pending in a state district court in
Colorado. At the center of the lawsuit is the validity of a contractual right
claimed by QTC to put its 50% interest in TransColorado to KNTC during the
12-month period beginning March 31, 2001. The current value of the put is $118
million.
KNTC filed a lawsuit in June of 2000 alleging that Questar Pipeline and its
affiliates breached their fiduciary duties to TransColorado and KNTC by
constructing and operating a pipeline (Questar Pipeline's Main Line 104) that
would compete with TransColorado, rendering TransColorado economically unviable.
KNTC is seeking damages in excess of $150 million plus punitive damages; a
declaratory judgment that KNTC's obligation to purchase QTC's interest in the
project be declared void and unenforceable; and a dissolution of the partnership
under Colorado law. QTC and its affiliates subsequently filed a counterclaim and
third-party complaint against KNTC and named affiliates, including Kinder
Morgan, Inc., seeking a declaratory judgment that its contractual right to
exercise the put is binding and enforceable and damages of at least $185
million.
The parties entered into a standstill agreement that preserves the claims made
by Questar and by KNTC pending the resolution of the litigation. On December 31,
2000, QTC gave notice of its election to exercise its contractual right to sell
its 50% interest in TransColorado to KNTC.
The parties have engaged in extensive discovery proceeding and used a special
master to review some issues raised in discovery. The trial is scheduled to
begin April 1, 2002.
-68-
<Page>
GRYNBERG LAWSUITS
Questar affiliates are named defendants in a lawsuit filed by independent gas
producer Jack J. Grynberg under the Federal False Claims Act. This case and all
substantially similar cases filed by Grynberg against pipelines and their
affiliates have been consolidated for discovery and pre-trial rulings in Wyoming
federal district court. The cases involve allegations of industry wide
mismeasurement and undervaluation of gas on which royalty payments are due the
federal government. The complaint seeks treble damages and imposition of civil
penalties. The Wyoming district court judge denied the defendants' initial
motion to dismiss. No motions are currently pending.
Grynberg has filed a case against Questar Pipeline, Questar Energy Trading and
Questar Gas Management in Utah state district court, alleging mismeasurement of
gas volumes attributable to his working ownership interest in a specified
property in southwestern Wyoming. Grynberg alleges breach of contract, negligent
misrepresentation, fraud, breach of fiduciary duty, etc. On March 13, 2001, the
trial judge granted defendants' motion to dismiss the case by Grynberg and
Grynberg appealed that ruling to the Utah Supreme Court. Briefing of the case is
currently taking place.
It is too early to estimate the outcome of the cases filed by Grynberg against
Questar affiliates.
WILL PRICE V. GAS PIPELINES ET AL. (FORMERLY QUINQUE OPERATING CO. V. GAS
PIPELINES)
A number of the Company's subsidiaries are named defendants in a purported
nationwide class action alleging mismeasurement of volumes and heating content
of gas produced from private and state lands. The plaintiffs are alleging a
conspiracy among the defendants to set industry standards that undermeasure gas.
The defendants have filed motions to dismiss the pending actions for lack of
personal jurisdiction and for failure to state a claim. The producer's complaint
does not include a request for any specific monetary damages.
OTHER LEGAL PROCEEDINGS
There are various other legal proceedings against Questar and its subsidiaries.
While it is not currently possible to predict or determine the outcomes of these
proceedings, it is the opinion of management that the outcomes will not have a
materially adverse effect on the Company's results of operations, financial
position or liquidity.
COMMITMENTS
Historically, 40% to 50% of Questar Gas' gas-supply portfolio has been provided
from company-owned gas reserves at the cost of service. The remainder of the gas
supply has been purchased from various suppliers under agreements with a
duration of one year or less and index-based pricing. Generally, at the
conclusion of the heating season and after a bid process, new agreements for the
upcoming heating season are put into place. Questar Gas bought significant
quantities of natural gas under purchase agreements amounting to $261 million,
$184 million and $93 million in 2001, 2000 and 1999, respectively. In addition,
Questar Gas makes use of various storage arrangements to meet peak-gas demand
during certain times of the heating season.
Questar Energy Trading has contracted for firm-transportation services with
various pipelines through 2016. Due to market conditions and competition, it is
possible that Questar Energy Trading may not be able to recover the full cost of
these transportation commitments. Annual payments and the years covered are as
follows:
<Table>
<Caption>
(In Thousands)
--------------
2002 $3,351
2003 2,489
2004 1,681
Yearly commitment fee
2005 through 2016 194
</Table>
-69-
<Page>
Questar sold its headquarters building under a sale and lease-back arrangement
in November 1998. The operating agreement commits the Company to occupy the
building through January 12, 2012. Questar has four renewal options of five
years each. Minimum future payments under the terms of long-term operating
leases for the Company's primary office locations, including its headquarters
building, for the five years following December 31, 2001, are as follows:
<Table>
<Caption>
(In Thousands)
--------------
2002 $ 4,834
2003 4,655
2004 4,169
2005 3,896
2006 3,726
2007 through 2012 21,799
</Table>
Total minimum future rental payments have not been reduced for sublease rentals
of $710,000 expected to be received through 2006. Total rental expense amounted
to $4,658,000 in 2001, $4,402,000 in 2000 and $4,321,000 in 1999. Sublease
rental receipts were $294,000 in 2001, $118,000 in 2000 and $94,000 in 1999.
Note 9 - Rate Regulation and Other Matters
STATE RATE REGULATION
Questar Gas routinely files periodic applications with the Public Service
Commission of Utah (PSCU) and the Public Service Commission of Wyoming (PSCW)
requesting permission to reflect annualized gas cost increases or decreases
depending on gas prices. These requests for gas cost increases or decreases are
passed on to customers on a dollar-for-dollar basis with no markup. The impact
of the gas cost increase on customers was lessened by the fact that
approximately 40% to 50% of the Company's annual supply comes from its own wells
and is priced to customers at cost-of-service prices rather than market prices.
Effective January 1, 2001, the PSCU approved on an interim basis a $167 million
increase in its Utah natural gas rates that resulted in a 29 percent increase
for the typical residential Utah customer. The increase was based on significant
increases in natural gas prices at the wellhead and was part of Questar Gas'
gas-cost-adjustment or "pass-through" filings. Also, effective January 1, 2001,
the PSCW approved a $7 million pass-through filing for Wyoming natural gas
rates.
On August 30, 2001, the Company filed a pass-on request with the PSCW seeking a
$4.6 million reduction of future gas costs collected in rates. The PSCW approved
the request. On September 17, 2001, Questar Gas filed a pass-through request
with the PSCU that reduced gas costs in Utah rates by $110.9 million over the 12
months following an October 1, 2001 effective date. The PSCU approved the
request.
On November 30, 2001, the Company filed a pass-on request with the PSCW asking
to reduce future gas costs collected in rates by $2.9 million. The request was
approved effective January 1, 2002. In a similar request, the Company filed a
pass-through rate request with the PSCU asking for a $66.9 million reduction of
future gas costs. The PSCU granted the request effective January 1, 2002. In
total, pass-through reductions filed between August 2001 and January 2002,
resulted in a 25% decrease for a typical Utah residential customer.
On October 23, 2001, the Utah Supreme Court unanimously reversed a PSCU decision
and agreed with Questar Gas' position that certain gas processing costs should
have been considered for recovery through usual pass-through proceedings. In
December 1999, PSCU denied the Company's request to recover certain costs of
processing gas to remove carbon dioxide. In denying the Company's request, the
PSCU provided guidance to seek recovery of future processing fees through other
rate making procedures. The Company filed a general rate case that, when settled
in August 2000, provided $5 million yearly toward processing costs. The Company
appealed to the Utah Supreme Court, maintaining that the purchase-gas adjustment
account and pass-through proceedings were the proper
-70-
<Page>
mechanisms for recovering those processing costs. The court's decision sends the
case back to the PSCU and allows the opportunity for the Company to seek
recovery of incurred costs.
FEDERAL RATE REGULATION
On September 27, 2001, the Federal Energy Regulatory Commission (FERC) issued a
Notice of Proposed Rule making on Standards of Conduct for Transmission
Providers (NOPR) that would significantly broaden the scope of the FERC's
affiliate regulations for pipelines. The NOPR would require all transmission
providers to comply with standards of conduct dealing with affiliated energy
companies. Those standards include the separation of functions and
non-discriminatory treatment of transmission customers. The NOPR would
essentially diminish operational efficiencies and increase costs by mandating a
complete separation of operations. Questar Regulated Services supplies
administrative, technical, accounting, legal and regulatory support for both
Questar Pipeline and Questar Gas.
Questar Gas, Questar Pipeline, industry associations and other companies have
filed written and verbal comments with the FERC about the problems this NOPR
would create for the industry and its customers and asked the FERC to reconsider
its proposal.
CPUC DECISION AND SOUTHERN TRAILS
A ruling from the California Public Utilities Commission (CPUC) on Residual Load
Service tariff has adverse effects on new pipelines attempting to enter the
California market. Under the CPUC's proposed new peaking rate, new gas fired
power plants wanting natural gas service from both Southern California Gas
(SoCal) and a new competing pipeline will pay a higher rate for SoCal's service
than captive customers taking service entirely from SoCal. In addition, new
power plants would be subject to more restrictive balancing services than
captive customers and would pay even more for interruptible service than
California power plants in other parts of the state. While the Company continues
to actively pursue natural gas markets on the California portion of its Southern
Trails Pipeline, the Company is considering alternative uses as well.
Note 10 - Employee Benefits
Pension Plan: The Company has a defined-benefit pension plan covering the
majority of its employees. Benefits are generally based on the employee's age at
retirement, years of service and highest earnings in a consecutive 72 pay-period
interval during the ten years preceding retirement. The Company's policy is to
make contributions to the plan at least sufficient to meet the minimum funding
requirements of the Internal Revenue Code. Plan assets consist principally of
equity securities and corporate and U.S. government debt obligations. The
Company relies on a third-party consultant to calculate the pension plan
projected benefit obligation.
The Company offered early retirement windows to specific groups of employees in
2000 and 1999. Regulated Services offered early retirement windows to eligible
employees in 2000 with a total of 276 employees and recipients of long-term
disability from Questar Gas, Questar Pipeline and Questar Regulated Services
electing to retire effective October 31, 2000. The $14.4 million cost of the
early retirement window is being amortized over a five-year period in accordance
with regulatory treatment.
Questar InfoComm, which conducts telecommunications and information-technology
services, announced an early retirement program effective November 1, 1999.
Fifty employees elected to retire and the $2.9 million cost was expensed in
1999.
-71-
<Page>
A summary of pension expense is as follows:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
----------------------------------------------------------
(In Thousands)
Service cost $ 7,038 $ 7,354 $ 8,894
Interest cost 16,914 18,447 18,814
Expected return on plan assets (17,065) (23,782) (24,059)
Prior service and other costs 1,978 1,581 1,365
Recognized net actuarial gain (16) (552)
Amortization of early retirement costs 3,504 1,340 3,744
----------------------------------------------------------
Pension expense $ 12,353 $ 4,388 $ 8,758
==========================================================
</Table>
Assumptions used to calculate pension expense were as follows:
<Table>
<Caption>
2001 2000 1999
--------------------------------------------------------
Discount rate 7.75% 7.75% 6.75%
Rate of increase in compensation 5.00% 5.00% 5.00%
Long-term return on assets 9.25% 9.25% 9.25%
</Table>
The status of the pension plan was as follows:
<Table>
<Caption>
Pension Plan 2001 2000
----------------------------------
(In Thousands)
Change in benefit obligation
Projected benefit obligation at January 1, $ 222,787 $ 246,958
Service cost 7,038 7,354
Interest cost 16,914 18,447
Plan amendments 8,153
Change in plan assumptions (234)
Actuarial loss 926 34,096
Benefits paid (11,409) (11,275)
Early retirement settlements paid (80,946)
---------------------------------
Projected benefit obligation at December 31, 236,022 222,787
---------------------------------
Change in plan assets
Fair value of plan assets at January 1, 189,970 274,907
Actual return (loss) on plan assets (2,169) 4,284
Contributions to the plan 12,369 3,000
Benefits paid (11,409) (11,275)
Early retirement settlements paid (80,946)
---------------------------------
Fair value of plan assets at December 31, 188,761 189,970
---------------------------------
Plan assets less the projected
benefit obligation (47,261) (32,817)
Unrecognized net actuarial loss 23,049 3,053
Unrecognized prior-service cost 17,228 19,138
Unrecognized transition obligation 67
---------------------------------
Accrued pension expense payable
recorded in current liabilities ($ 6,984) ($ 10,559)
=================================
</Table>
Postretirement Benefits Other Than Pensions: Postretirement health-care benefits
and life insurance are provided only to employees hired before January 1, 1997.
The Company pays a portion of the costs of health-care
-72-
<Page>
benefits, as determined by an employee's years of service, and limited to 170%
of the 1992 contribution. The Company's policy is to fund amounts allowable for
tax deduction under the Internal Revenue Code. Plan assets consist of equity
securities and corporate and U.S. government debt obligations. The Company is
amortizing its transition obligation over a 20-year period, which began in 1992.
The Company relies on a third-party consultant to calculate the projected
benefit obligation.
Regulated Services accounted for approximately 55% of the postretirement benefit
expense in 2001. The impact of postretirement benefit costs on Questar's future
net income will be mitigated by the ability to recover these costs from
customers. The regulatory agencies allow Questar Gas and Questar Pipeline to
recover costs if the amounts are funded in external trusts.
A summary of the expense of postretirement benefits other than pensions follows:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
----------------------------------
(In Thousands)
Service cost $ 878 $ 823 $ 1,006
Interest cost 5,686 4,979 4,545
Expected return on plan assets (3,213) (3,241) (2,831)
Amortization of transition obligation 1,877 1,877 1,877
Amortization of regulatory liability (524) 523
-----------------------------------
Postretirement benefit expense $ 4,704 $ 4,438 $ 5,120
===================================
</Table>
Assumptions used to calculate postretirement benefit expense were as follows:
<Table>
<Caption>
2001 2000 1999
-----------------------------------------
Discount rate 7.75% 7.75% 6.75%
Long-term return on assets 9.25% 9.25% 9.25%
Health care inflation rate 10.00% 10.00% 10.50%
decreasing to decreasing to decreasing to
6.5% by 2008 6.5% by 2008 5.5% by 2010
</Table>
A 1% increase in the health-care inflation rate would increase the service cost
and interest cost by $162,000 and the accumulated postretirement benefit
obligation by $2.3 million. A 1% decrease in the health-care inflation rate
would decrease the service cost and interest cost by $144,000 and the
accumulated postretirement benefit obligation by $2.1 million. The status of the
postretirement benefit programs was as follows:
Postretirement Benefits Other Than Pensions
<Table>
<Caption>
2001 2000
---------------------------------
(In Thousands)
Change in benefit obligation
Projected benefit obligation at January 1, $ 67,864 $ 66,169
Service cost 878 823
Interest cost 5,686 4,979
Actuarial (gain) loss 10,113 (701)
Benefits paid (4,840) (3,406)
---------------------------------
Projected benefit obligation at December 31, 79,701 67,864
---------------------------------
</Table>
-73-
<Page>
<Table>
<Caption>
2001 2000
---------------------------------
(In Thousands)
Change in plan assets
Fair value of plan assets at January 1, 35,302 35,302
Actual return (loss) on plan assets (531) 389
Contributions to the plan 4,413 3,017
Benefits paid (4,840) (3,406)
---------------------------------
Fair value of plan assets at December 31, 34,344 35,302
---------------------------------
Projected benefit obligation
in excess of plan assets (45,357) (32,562)
Unrecognized transition obligation 20,652 22,529
Unrecognized net (gain) loss 11,415 (2,442)
---------------------------------
Accrued postretirement benefit
recorded in current liabilities ($13,290) ($12,475)
=================================
</Table>
Postemployment Benefits: The Company recognizes the net present value of the
liability for postemployment benefits, such as long-term disability benefits and
health-care and life-insurance costs, when employees become eligible for such
benefits. Postemployment benefits are paid to former employees after employment
has been terminated but before retirement benefits are paid. The Company accrues
both current and future costs. In 2000, certain recipients of postemployment
benefits accepted early retirement benefits in connection with Questar Regulated
Services' early retirement program. Questar's postemployment liability at
December 31, 2001, 2000 and 1999 was $1.3 million, $1.4 million, and $2.3
million, respectively.
Note 11 - Wexpro Settlement Agreement
Wexpro's operations are subject to the terms of the Wexpro settlement agreement.
The agreement was effective August 1, 1981, and sets forth the rights of Questar
Gas's utility operations to share in the results of Wexpro's operations. The
agreement was approved by the PSCU and PSCW in 1981 and affirmed by the Supreme
Court of Utah in 1983. Major provisions of the settlement agreement are as
follows:
a. Wexpro continues to hold and operate all oil-producing properties previously
transferred from Questar Gas's nonutility accounts. The oil production from
these properties is sold at market prices, with the revenues used to recover
operating expenses and to give Wexpro a return on its investment. The after-tax
rate of return is adjusted annually and is approximately 13.6%. Any net income
remaining after recovery of expenses and Wexpro's return on investment is
divided between Wexpro and Questar Gas, with Wexpro retaining 46%.
b. Wexpro conducts developmental oil drilling on productive oil properties and
bears any costs of dry holes. Oil discovered from these properties is sold at
market prices, with the revenues used to recover operating expenses and to give
Wexpro a return on its investment in successful wells. The after-tax rate of
return is adjusted annually and is approximately 18.6%. Any net income remaining
after recovery of expenses and Wexpro's return on investment is divided between
Wexpro and Questar Gas, with Wexpro retaining 46%.
c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are
used to reduce natural-gas costs to utility customers.
d. Wexpro conducts developmental gas drilling on productive gas properties and
bears any costs of dry holes. Natural gas produced from successful drilling is
owned by Questar Gas. Wexpro is reimbursed for the costs of producing the gas
plus a return on its investment in successful wells. The after-tax return
allowed Wexpro is approximately 21.6%.
e. Wexpro operates natural-gas properties owned by Questar Gas. Wexpro is
reimbursed for its costs of operating these properties, including a rate of
return on any investment it makes. This after-tax rate of return is
approximately 13.6%.
-74-
<Page>
Note 12 - Operations by Line of Business
Following is a summary of operations by line of business for the Year Ended
December 31.
<Table>
<Caption>
Questar Regulated Services
-------------------------------------
Questar Natural Gas Natural Gas Other Corporate Intercompany Questar
Market Distribution Transmission & Other Transactions Consolidated
Resources Operations
---------------------------------------------------------------------------------------------------------
(In Thousands)
2001
----
Revenues
From unaffiliated customers $ 645,867 $ 701,150 $ 49,402 $ 4,603 $ 38,328 $ 1,439,350
From affiliated companies 100,530 2,963 75,491 1,463 29,444 ($ 209,891)
--------------------------------------------------------------------------------------------
746,397 704,113 124,893 6,066 67,772 (209,891) 1,439,350
Operating expenses
Cost of natural gas and
other products sold 324,124 498,545 2,204 25,949 (175,811) 675,011
Operating and maintenance 112,087 103,427 47,244 3,665 35,127 (31,195) 270,355
Exploration 6,986 6,986
Depreciation, depletion and
amortization 92,678 35,030 15,407 213 8,407 151,735
Abandonment and impairment
of oil and gas properties 5,171 5,171
Other expenses 46,010 8,729 2,920 67 1,144 (2,885) 55,985
--------------------------------------------------------------------------------------------
Total operating expenses 587,056 645,731 65,571 6,149 70,627 (209,891) 1,165,243
--------------------------------------------------------------------------------------------
Operating income (loss) 159,341 58,382 59,322 (83) (2,855) 274,107
Interest and other income 17,618 5,158 5,950 5,374 14,957 (12,034) 37,023
Income (loss) from
unconsol. affiliates 1,265 (1,106) 159
Debt expense (22,872) (23,777) (16,908) (572) (12,738) 12,034 (64,833)
Income tax expense (54,218) (13,890) (17,517) (1,888) (757) (88,270)
--------------------------------------------------------------------------------------------
Net income (loss) $ 101,134 $ 25,873 $ 29,741 $ 2,831 ($ 1,393) $ 158,186
============================================================================================
Identifiable assets $ 1,510,699 $ 833,268 $ 772,197 $ 25,749 $ 93,798 $ 3,235,711
Investment in unconsol affiliates 23,829 121,099 144,928
Capital expenditures 638,507 78,791 256,703 2,860 7,225 984,086
2000
----
Revenues
From unaffiliated customers $ 649,200 $ 531,988 $ 42,500 $ 3,642 $ 38,823 $ 1,266,153
From affiliated companies 92,853 4,774 76,576 283 34,586 ($ 209,072)
--------------------------------------------------------------------------------------------
742,053 536,762 119,076 3,925 73,409 (209,072) 1,266,153
Operating expenses
Cost of natural gas and
other products sold 369,752 334,193 2,253 24,640 (168,609) 562,229
Operating and maintenance 106,761 101,486 43,761 1,668 33,506 (35,705) 251,477
Exploration 7,917 7,917
Depreciation, depletion and
amortization 85,025 34,450 15,391 35 7,590 142,491
Abandonment and impairment
of oil and gas properties 3,418 3,418
Other expenses 41,020 10,213 3,071 35 1,073 (4,758) 50,654
--------------------------------------------------------------------------------------------
Total operating expenses 613,893 480,342 62,223 3,991 66,809 (209,072) 1,018,186
--------------------------------------------------------------------------------------------
Operating income (loss) 128,160 56,420 56,853 (66) 6,600 247,967
Interest and other income 8,412 1,673 3,025 1,349 36,926 (11,922) 39,463
Income from unconsol affiliates 2,776 1,220 3,996
Debt expense (22,922) (21,041) (17,584) (722) (13,163) 11,922 (63,510)
Income tax expense (38,618) (12,889) (13,689) (217) (13,026) (78,439)
--------------------------------------------------------------------------------------------
Net income $ 77,808 $ 24,163 $ 29,825 $ 344 $ 17,337 $ 149,477
============================================================================================
</Table>
-75-
<Page>
Note 12 - Operations by Line of Business
Following is a summary of operations by line of business for the Year Ended
December 31.
<Table>
<Caption>
Questar Regulated
Services
--------------------------------------------------------
Questar Natural Gas Natural Gas Other Corporate Intercompany Questar
Market Distribution Transmission & Other Transactions Consolidated
Resources Operations
------------------------------------------------------------------------------------------------------
(In Thousands)
Identifiable assets $ 960,491 $ 830,889 $ 538,408 $ 19,640 $ 122,599 $ 2,472,027
Investment in unconsol
affiliates 15,417 19,088 34,505
Capital expenditures 187,359 65,767 43,035 1,167 17,814 315,142
1999
----
Revenues
From unaffiliated
customers $ 418,603 $ 447,606 $ 36,922 $ 2,260 $ 18,828 $ 924,219
From affiliated companies 79,708 2,331 75,238 196 38,851 ($ 196,324)
------------------------------------------------------------------------------------------------------
498,311 449,937 112,160 2,456 57,679 (196,324) 924,219
Operating expenses
Cost of natural gas and
other products sold 239,201 257,265 774 9,651 (154,337) 352,554
Operating and maintenance 79,719 103,308 38,534 1,700 37,516 (39,695) 221,082
Exploration 5,321 5,321
Depreciation, depletion
and amortization 73,028 36,426 16,743 14 5,953 132,164
Abandonment and impairment
of oil and gas properties 7,535 7,535
Other expenses 23,808 7,625 2,488 24 1,071 (2,292) 32,724
------------------------------------------------------------------------------------------------------
Total operating expenses 428,612 404,624 57,765 2,512 54,191 (196,324) 751,380
------------------------------------------------------------------------------------------------------
Operating income (loss) 69,699 45,313 54,395 (56) 3,488 172,839
Interest and other income 8,272 2,980 4,229 1,014 73,406 (11,201) 78,700
Income (loss) from
unconsol. affiliates 763 (5,109) (10) (4,356)
Write-down of investment
in partnership (49,700) (49,700)
Debt expense (17,363) (20,062) (17,466) (605) (9,649) 11,201 (53,944)
Income tax (expense) credit (17,483) (9,012) 5,260 (102) (25,350) (46,687)
------------------------------------------------------------------------------------------------------
Net income (loss) $ 43,888 $ 19,219 ($ 8,391) $ 251 $ 41,885 $ 96,852
======================================================================================================
Identifiable assets $ 777,923 $ 722,290 $ 517,981 $ 11,423 $ 155,117 $ 2,184,734
Investment in unconsol
affiliates 13,301 11,724 244 25,269
Capital expenditures 128,248 68,447 50,424 1,385 13,479 261,983
</Table>
Questar Market Resources has subsidiaries that conduct gas and oil exploration
and production activities in western Canada. Canadian operations reported
revenues, measured in U. S. dollars, totaling $38.5 million, $38.1 million and
$12.3 million for the year ended December 31, 2001, 2000 and 1999, respectively.
Total assets at December 31, stated in U. S. dollars, amounted to $84.6 million,
$103.9 million and $31.0 million in 2001, 2000 and 1999, respectively.
-76-
<Page>
Note 13 - Quarterly Financial and Stock Price Information (Unaudited)
Following is a summary of quarterly financial and stock price data.
<Table>
<Caption>
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
--------------------------------------------------------------
(Dollars In Thousands, Except Per Share Amounts)
2001
----
Revenues $ 562,638 $ 285,138 $ 225,142 $ 366,432 $1,439,350
Operating income 110,386 49,049 47,045 67,627 274,107
Net income 69,260 24,503 21,842 42,581 158,186
Basic earnings per common share 0.86 0.30 0.27 0.52 1.95
Diluted earnings per common share 0.85 0.30 0.27 0.52 1.94
Dividends per common share 0.175 0.175 0.175 0.18 0.705
Market price per common share
High $ 29.95 $ 33.75 $ 25.12 $ 25.48 $ 33.75
Low $ 26.35 $ 24.00 $ 18.58 $ 19.60 $ 18.58
Close $ 27.40 $ 24.76 $ 20.18 $ 25.05 $ 25.05
Price-earnings ratio on closing price 12.9
Annualized dividend yield on closing price 2.6% 2.8% 3.5% 2.8% 2.8%
Market-to-book ratio on closing price 1.89
Average number of common shares traded per day 221 314 275 199 252
2000
----
Revenues $ 336,702 $ 232,542 $ 245,117 $ 451,792 $1,266,153
Operating income 78,653 41,240 43,521 84,553 247,967
Net income 48,568 24,155 26,406 50,348 149,477
Basic earnings per common share 0.60 0.30 0.33 0.63 1.86
Diluted earnings per common share 0.60 0.30 0.33 0.62 1.85
Dividends per common share 0.17 0.17 0.17 0.175 0.685
Market price per common share
High $ 19.00 $ 20.63 $ 28.00 $ 31.88 $ 31.88
Low $ 13.56 $ 17.13 $ 18.88 $ 26.00 $ 13.56
Close $ 18.56 $ 19.38 $ 27.81 $ 30.06 $ 30.06
Price-earnings ratio on closing price 16.3
Annualized dividend yield on closing price 3.7% 3.5% 2.4% 2.3% 2.3%
Market-to-book ratio on closing price 2.55
Average number of common shares traded per day 233 169 237 280 230
1999
Revenues $ 277,814 $ 177,858 $ 183,070 $ 285,477 $ 924,219
Operating income 66,691 30,402 27,346 48,400 172,839
Net income 42,926 22,966 15,051 15,909 96,852
Basic earnings per common share 0.52 0.28 0.18 0.19 1.17
Diluted earnings per common share 0.52 0.28 0.18 0.19 1.17
Dividends per common share 0.165 0.165 0.17 0.17 0.67
Market price per common share
High $ 19.38 $ 19.94 $ 19.63 $ 19.13 $ 19.94
Low $ 16.13 $ 15.81 $ 17.88 $ 14.75 $ 14.75
Close $ 16.94 $ 19.13 $ 18.13 $ 15.00 $ 15.00
Price-earnings ratio on closing price 12.8
Annualized dividend yield on closing price 3.9% 3.5% 3.8% 4.5% 4.5%
Market-to-book ratio on closing price 1.36
Average number of common shares traded per day 201 147 138 179 166
</Table>
-77-
<Page>
Note 14 - Supplemental Gas and Oil Information (Unaudited)
The Company uses the successful efforts accounting method for its gas and oil
exploration and development activities. As ordered by the Public Service
Commission of Utah, the successful efforts method of accounting is utilized with
respect to costs associated with certain cost-of-service gas and oil properties
managed and developed by Wexpro and regulated for ratemaking purposes.
Cost-of-service gas and oil properties are those properties for which the
operations and return on investment are regulated by the Wexpro settlement
agreement (See Note 11).
Gas and Oil Exploration and Development Activities: The following information is
provided with respect to Questar's gas and oil exploration and development
activities, located in the United States and Canada.
CAPITALIZED COSTS
The aggregate amounts of costs capitalized for gas and oil exploration and
development activities and the related amounts of accumulated depreciation,
depletion and amortization follow:
<Table>
<Caption>
---------------------------------------
AS OF DECEMBER 31, United States Canada Total
- ------------------ ---------------------------------------
(In Thousands)
2001
- ----
Proved properties $ 1,051,875 $ 123,557 $1,175,432
Unproved properties 165,066 11,075 176,141
Support equipment and facilities 11,017 397 11,414
---------------------------------------
1,227,958 135,029 1,362,987
Accumulated depreciation, depletion and amortization 403,251 58,892 462,143
---------------------------------------
$ 824,707 $ 76,137 $ 900,844
=======================================
2000
- ----
Proved properties $ 732,078 $ 113,407 $ 845,485
Unproved properties 30,940 24,668 55,608
Support equipment and facilities 12,002 1,177 13,179
---------------------------------------
775,020 139,252 914,272
Accumulated depreciation, depletion and amortization 361,401 50,105 411,506
---------------------------------------
$ 413,619 $ 89,147 $ 502,766
=======================================
1999
- ----
Proved properties $ 663,051 $ 54,096 $ 717,147
Unproved properties 41,654 9,970 51,624
Support equipment and facilities 12,418 990 13,408
---------------------------------------
717,123 65,056 782,179
Accumulated depreciation, depletion and amortization 314,986 38,413 353,399
---------------------------------------
$ 402,137 $ 26,643 $ 428,780
=======================================
</Table>
-78-
<Page>
COSTS INCURRED
The following costs were incurred in gas and oil exploration and development
activities:
<Table>
<Caption>
---------------------------------------
AS OF DECEMBER 31, United States Canada Total
- ------------------ ---------------------------------------
(In Thousands)
2001
- ----
Property acquisition
Unproved $ 1,309 $ 318 $ 1,627
Proved 303,757 303,757
Exploration 14,063 1,755 15,818
Development 130,638 5,256 135,894
---------------------------------------
$ 449,767 $ 7,329 $ 457,096
=======================================
2000
- ----
Property acquisition
Unproved $ 3,054 $ 14,703 $ 17,757
Proved 1,202 31,058 32,260
Exploration 6,433 3,664 10,097
Development 64,582 29,478 94,060
---------------------------------------
$ 75,271 $ 78,903 $ 154,174
=======================================
1999
- ----
Property acquisition
Unproved $ 12,565 $ 337 $ 12,902
Proved 2,367 17 2,384
Exploration 8,402 323 8,725
Development 53,347 3,608 56,955
---------------------------------------
$ 76,681 $ 4,285 $ 80,966
=======================================
</Table>
RESULTS OF OPERATIONS
Following are the results of operations of Market Resources' gas and oil
exploration and development activities, before corporate overhead and interest
expenses.
<Table>
<Caption>
---------------------------------------
United States Canada Total
---------------------------------------
YEAR ENDED DECEMBER 31, 2001 (In Thousands)
- ----------------------------
Revenues
From unaffiliated customers $ 242,081 $ 38,495 $ 280,576
From affiliates 807 807
---------------------------------------
Total revenues 242,888 38,495 281,383
---------------------------------------
Production expenses 62,646 8,106 70,752
Exploration 5,236 1,785 7,021
Depreciation, depletion and amortization 58,537 12,064 70,601
Abandonment and impairment of gas
and oil properties 3,571 1,600 5,171
---------------------------------------
Total expenses 129,990 23,555 153,545
---------------------------------------
Revenues less expenses 112,898 14,940 127,838
Income taxes - Note A 37,348 9,323 46,671
---------------------------------------
Results of operations before corporate
overhead and interest expenses $ 75,550 $ 5,617 $ 81,167
=======================================
</Table>
-79-
<Page>
<Table>
<Caption>
---------------------------------------
United States Canada Total
---------------------------------------
YEAR ENDED DECEMBER 31, 2001 (In Thousands)
- ----------------------------
Revenues
From unaffiliated customers $ 207,656 $ 38,072 $ 245,728
From affiliates 18 18
---------------------------------------
Total revenues 207,674 38,072 245,746
---------------------------------------
Production expenses 49,056 8,809 57,865
Exploration 5,533 2,442 7,975
Depreciation, depletion and amortization 51,973 13,196 65,169
Abandonment and impairment of gas
and oil properties 2,327 1,091 3,418
---------------------------------------
Total expenses 108,889 25,538 134,427
---------------------------------------
Revenues less expenses 98,785 12,534 111,319
Income taxes - Note A 31,994 5,841 37,835
---------------------------------------
Results of operations before corporate
overhead and interest expenses $ 66,791 $ 6,693 $ 73,484
=======================================
Year Ended December 31, 1999
- ---------------------------------------
Revenues $ 150,159 $ 12,316 $ 162,475
---------------------------------------
Production expenses 41,856 3,681 45,537
Exploration 4,803 321 5,124
Depreciation, depletion and amortization 51,927 3,550 55,477
Abandonment and impairment of gas
and oil properties 5,542 1,993 7,535
---------------------------------------
Total expenses 104,128 9,545 113,673
---------------------------------------
Revenues less expenses 46,031 2,771 48,802
Income taxes - Note A 12,348 1,233 13,581
---------------------------------------
Results of operations before corporate
overhead and interest expenses $ 33,683 $ 1,538 $ 35,221
=======================================
</Table>
Note A - Income tax expenses have been reduced by non-conventional fuel tax
credits of $5 million in 2001, $4.7 million in 2000 and $5.3 million in 1999.
-80-
<Page>
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES
Estimates of the reserves located in the United States were made by Ryder Scott
Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, and
Malkewicz Hueni Associates, Inc., independent reservoir engineers. Estimated
Canadian reserves were prepared by Gilbert Laustsen Jung Associates Ltd. and
Sproule Associates Ltd. Reserve estimates are based on a complex and highly
interpretive process that is subject to continuous revision as additional
production and development-drilling information becomes available. The
quantities reported below are based on existing economic and operating
conditions at December 31. All gas and oil reserves reported were located in the
United States and Canada. The Company does not have any long-term supply
contracts with foreign governments or reserves of equity investees.
<Table>
<Caption>
NATURAL GAS OIL
----------- ---
United States Canada Total United States Canada Total
-----------------------------------------------------------------------------
PROVED RESERVES (MMcf) (MBbls)
- ---------------
Balance at January 1, 1999 466,688 21,935 488,623 11,649 2,601 14,250
Revisions of estimates 4,155 (106) 4,049 4,031 372 4,403
Extensions and discoveries 77,737 1,720 79,457 794 257 1,051
Purchase of reserves in place 17,020 17,020 130 130
Sale of reserves in place (11,984) (11,984) (3,665) (3,665)
Production (59,839) (2,873) (62,712) (1,876) (435) (2,311)
-----------------------------------------------------------------------------
Balance at December 31, 1999 493,777 20,676 514,453 11,063 2,795 13,858
Revisions of estimates 25,662 (7,890) 17,772 221 (64) 157
Extensions and discoveries 123,155 2,511 125,666 1,532 208 1,740
Purchase of reserves in place 846 52,000 52,846 1 1,520 1,521
Sale of reserves in place (1,885) (1,885) (17) (17)
Production (61,722) (7,241) (68,963) (1,484) (741) (2,225)
-----------------------------------------------------------------------------
Balance at December 31, 2000 579,833 60,056 639,889 11,316 3,718 15,034
Revisions of estimates (36,528) 1,341 (35,187) (1,950) (21) (1,971)
Extensions and discoveries 175,423 7,144 182,567 1,515 340 1,855
Purchase of reserves in place 300,353 300,353 19,185 19,185
Sale of reserves in place (19,072) (19,072) (531) (531)
Production (63,862) (6,712) (70,574) (1,797) (703) (2,500)
-----------------------------------------------------------------------------
Balance at December 31, 2001 936,147 61,829 997,976 27,738 3,334 31,072
=============================================================================
PROVED-DEVELOPED RESERVES
- -------------------------
Balance at January 1, 1999 411,826 17,835 429,661 10,443 2,281 12,724
Balance at December 31, 1999 412,008 17,076 429,084 9,897 2,565 12,462
Balance at December 31, 2000 434,122 55,623 489,745 9,696 3,077 12,773
Balance at December 31, 2001 534,761 53,036 587,797 19,417 2,566 21,983
</Table>
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES
Future net cash flows were calculated at December 31 using year-end prices and
known contract-price changes. The year-end prices do not include any impact of
hedging activities. Year-end production costs, development costs and appropriate
statutory income tax rates, with consideration of future tax rates already
legislated, were used to compute the future net cash flows. All cash flows were
discounted at 10% to reflect the time value of cash flows, without regard to the
risk of specific properties.
-81-
<Page>
The assumptions used to derive the standardized measure of future net cash flows
are those required by accounting standards and do not necessarily reflect the
Company's expectations. The usefulness of the standardized measure of future net
cash flows is impaired because of the reliance on reserve estimates and
production schedules that are inherently imprecise.
<Table>
<Caption>
-------------------------------------------
YEAR ENDED DECEMBER 31, United States Canada Total
-------------------------------------------
(In Thousands)
2001
Future cash inflows $ 2,541,716 $ 192,762 $ 2,734,478
Future production costs (798,431) (58,643) (857,074)
Future development costs (266,097) (3,421) (269,518)
Future income tax expenses (392,152) (38,767) (430,919)
-------------------------------------------
Future net cash flows 1,085,036 91,931 1,176,967
10% annual discount to reflect
timing of net cash flows (536,876) (35,789) (572,665)
-------------------------------------------
Standardized measure of discounted
future net cash flows $ 548,160 $ 56,142 $ 604,302
===========================================
2000
Future cash inflows $ 5,412,945 $ 568,771 $ 5,981,716
Future production costs (955,827) (73,583) (1,029,410)
Future development costs (107,355) (2,900) (110,255)
Future income tax expenses (1,489,267) (182,537) (1,671,804)
-------------------------------------------
Future net cash flows 2,860,496 309,751 3,170,247
10% annual discount to reflect
timing of net cash flows (1,316,114) (136,445) (1,452,559)
-------------------------------------------
Standardized measure of discounted
future net cash flows $ 1,544,382 $ 173,306 $ 1,717,688
===========================================
1999
Future cash inflows $ 1,332,761 $ 108,990 $ 1,441,751
Future production costs (398,591) (28,280) (426,871)
Future development costs (61,034) (3,146) (64,180)
Future income tax expenses (188,988) (10,353) (199,341)
---------------------------------------------
Future net cash flows 684,148 67,211 751,359
10% annual discount to reflect
timing of net cash flows (280,911) (23,652) (304,563)
-------------------------------------------
Standardized measure of discounted
future net cash flows $ 403,237 $ 43,559 $ 446,796
===========================================
</Table>
-82-
<Page>
The principal sources of change in the standardized measure of discounted future
net cash flows were:
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
-------------------------------------------
(In Thousands)
Beginning balance $ 1,717,688 $ 446,796 $ 348,376
Sales of oil and gas produced, net
of production costs (210,631) (187,881) (116,938)
Net changes in prices and
production costs (1,978,853) 1,638,170 171,392
Extensions and discoveries, less
related costs 133,866 492,398 79,511
Revisions of quantity estimates (31,451) 70,155 28,665
Purchase of reserves in place 303,757 32,260 2,384
Sale of reserves in place (41,225) (1,867) (33,043)
Change in future development (70,979) (17,770) (9,332)
Accretion of discount 171,769 44,680 34,837
Net change in income taxes 775,013 (776,276) (61,807)
Change in production rate (125,725) (50,077) (8,859)
Other (38,927) 27,100 11,610
-------------------------------------------
Net change (1,113,386) 1,270,892 98,420
-------------------------------------------
Ending balance $ 604,302 $ 1,717,688 $ 446,796
===========================================
</Table>
COST-OF-SERVICE ACTIVITIES
The following information is provided with respect to cost-of-service gas and
oil properties managed and developed by Wexpro and regulated by the Wexpro
settlement agreement. Information on the standardized measure of future net cash
flows has not been included for cost-of-service activities because the
operations of and return on investment for such properties are regulated by the
Wexpro settlement agreement.
CAPITALIZED COSTS
Capitalized costs for cost-of-service gas and oil properties net of the related
accumulated depreciation and amortization were as follows:
<Table>
<Caption>
December 31,
2001 2000 1999
-------------------------------------------
(In Thousands)
Wexpro $ 198,373 $ 155,374 $ 137,584
Questar Gas 20,991 22,620 25,380
-------------------------------------------
$ 219,364 $ 177,994 $ 162,964
===========================================
</Table>
COSTS INCURRED
Costs incurred by Wexpro for cost-of-service gas and oil producing activities
were $58.5 million in 2001, $32.1 million in 2000 and $21.3 million in 1999.
-83-
<Page>
RESULTS OF OPERATIONS
Following are the results of operations of the Company's cost-of-service gas and
oil development activities before corporate overhead and interest expenses.
<Table>
<Caption>
Year Ended December 31,
2001 2000 1999
-------------------------------------------
(In Thousands)
Revenues
From unaffiliated companies $ 12,465 $ 15,179 $ 8,844
From affiliates - Note A 88,936 73,721 62,335
-------------------------------------------
Total revenues 101,401 88,900 71,179
Production expenses 33,016 27,861 18,548
Depreciation and amortization 15,051 13,922 12,665
-------------------------------------------
Total expenses 48,067 41,783 31,213
-------------------------------------------
Revenues less expenses 53,334 47,117 39,966
Income taxes 19,181 16,923 14,602
-------------------------------------------
Results of operations before corporate
overhead and interest expenses $ 34,153 $ 30,194 $ 25,364
===========================================
</Table>
Note A - Represents revenues received from Questar Gas pursuant to Wexpro
Settlement Agreement.
ESTIMATED QUANTITIES OF PROVED GAS AND OIL RESERVES
The following estimates were made by the Company's reservoir engineers.
Generally, no estimates are available for cost-of-service proved undeveloped
reserves that may exist.
<Table>
<Caption>
Natural Gas Oil
----------------------------
(MMcf) (MBbls)
PROVED DEVELOPED RESERVES
Balance at January 1, 1999 340,135 2,723
Revisions of estimates 5,699 976
Extensions and discoveries 46,739 213
Production (38,890) (623)
----------------------------
Balance at December 31, 1999 353,683 3,289
Revisions of estimates 16,523 504
Extensions and discoveries 50,351 234
Production (41,546) (579)
----------------------------
Balance at December 31, 2000 379,011 3,448
Revisions of estimates (11,465) 275
Extensions and discoveries 76,042 479
Production (37,907) (515)
----------------------------
Balance at December 31, 2001 405,681 3,687
============================
</Table>
-84-
<Page>
QUESTAR CORPORATION AND SUBSIDIARIES
Schedule of Valuation and Qualifying Accounts
December 31, 2001
(In Thousands)
<Table>
<Caption>
- ------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Description Beginning Balance Amounts charged Deductions for Ending Balance
to expense accounts written off
- ------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2001
- ----------------------------
Allowance for bad
debts $3,470 $8,634 $5,793 $6,311
YEAR ENDED DECEMBER 31, 2000
- ----------------------------
Allowance for bad
debts 2,793 3,886 3,209 3,470
YEAR ENDED DECEMBER 31, 1999
- ----------------------------
Allowance for bad
debts 4,378 3,089 4,674 2,793
</Table>
-85-
<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, on the 27th day
of March, 2002
QUESTAR CORPORATION
(Registrant)
By /s/ R. D. Cash
-------------------------------------
R. D. Cash
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
/s/ R. D. Cash Chairman and Chief Executive
- ------------------------------ Officer (Principal Executive
R. D. Cash Officer)
/s/ S. E. Parks Senior Vice President, Treasurer and
- ------------------------------ Chief Financial Officer (Principal
S. E. Parks Financial and Accounting Officer)
*R. D. Cash Director
*K. O. Rattie Director
*Teresa Beck Director
*P. J. Early Director
*J. A. Harmon Director
*W. W. Hawkins Director
*Robert E. Kadlec Director
*Dixie L. Leavitt Director
*Gary G. Michael Director
*G. L. Nordloh Director
*Scott S. Parker Director
*K. O. Rattie Director
*D. N. Rose Director
*Harris H. Simmons Director
March 27, 2002 *By /s/ R. D. Cash
- -------------- ------------------------------------
Date R. D. Cash, Attorney in Fact
-86-
<Page>
EXHIBIT INDEX
<Table>
<Caption>
Exhibit
Number Description
- ------ -----------
2.* Plan and Agreement of Merger dated as of December 16, 1986, by and
among the Company, Questar Systems Corporation, and Universal
Resources Corporation. (Exhibit No. (2) to Current Report on Form 8-K
dated December 16, 1986.)
3.1.* Restated Articles of Incorporation as amended effective May 19, 1998.
(Exhibit No. 3.1. to Form 10-Q Report for Quarter ended June 30,
1998.)
3.2.* Bylaws (as amended effective October 25, 2001). (Exhibit No. 3.1. to
Form 10-Q Report for Quarter ended September 30, 2001.)
4.1.*(1) Rights Agreement dated as of February 13, 1996, between the Company
and Chemical Mellon Shareholder Services L.L.C. pertaining to the
Company's Shareholder Rights Plan. (Exhibit No. 4. to Current Report
on Form 8-K dated February 13, 1996.)
4.2.* Questar Dividend Reinvestment and Stock Purchase Plan. (Exhibit No.
4. to Current Report on Form 8-K dated February 8, 2000.)
10.1.* Stipulation and Agreement, dated October 14, 1981, executed by
Mountain Fuel; Wexpro; the Utah Department of Business Regulations,
Division of Public Utilities; the Utah Committee of Consumer
Services; and the staff of the Public Service Commission of Wyoming.
(Exhibit No. 10(a) to Mountain Fuel Supply Company's Form 10-K Annual
Report for 1981.)
10.2.*(2) Questar Corporation Annual Management Incentive Plan, as amended and
restated effective February 13, 2001. (Exhibit No. 10.2. to Form 10-K
Annual Report for 2000.)
10.3.*(2) Questar Corporation Executive Incentive Retirement Plan, as amended
and restated effective May 19, 1998. (Exhibit No. 10.2. to Form 10-Q
Report for Quarter Ended June 30, 1998.)
10.4.*(2) Questar Corporation Long-Term Stock Incentive Plan, as amended and
restated effective March 1, 2001. (Exhibit No. 10.4. to Form 10-K
Annual Report for 2000.)
10.5.*(2) Questar Corporation Executive Severance Compensation Plan, as amended
and restated effective May 19, 1998. (Exhibit No. 10.3. to Form 10-Q
Report for Quarter Ended June 30, 1998.)
10.6.*(2) Questar Corporation Deferred Compensation Plan for Directors, as
amended and restated effective October 26, 2000. (Exhibit No. 10.6.
to Form 10-K Annual Report for 2000.)
10.7.*(2) Questar Corporation Supplemental Executive Retirement Plan, as
amended and restated effective June 1, 1998. (Exhibit No. 10.6. to
Form 10-Q Report for Quarter Ended June 30, 1998.)
</Table>
<Page>
<Table>
10.8.*(2) Questar Corporation Stock Option Plan for Directors, as amended and
restated effective October 29, 1998. (Exhibit No. 10.10. to Form 10-Q
Report for Quarter Ended September 30, 1998.)
10.9.*(2) Form of Individual Indemnification Agreement dated February 9, 1993
between Questar Corporation and Directors. (Exhibit No. 10.11. to
Form 10-K Annual Report for 1992.)
10.10.(2) Questar Corporation Deferred Share Plan, as amended and restated
effective January 1, 2002.
10.11.(2) Questar Corporation Deferred Compensation Plan, as amended and
restated effective January 1, 2002.
10.12.*(2) Questar Corporation Directors' Stock Plan as approved May 21, 1996.
(Exhibit No. 10.15. to Form 10-Q Report for Quarter ended June 30,
1996.)
10.13. Questar Corporation Deferred Share Make-Up Plan as amended and
restated effective January 1, 2002.
10.14.*(2) Questar Corporation Special Situation Retirement Plan. (Exhibit No.
10.10. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.15.*(2) Employment Agreement between the Company and Keith O. Rattie
effective February 1, 2001. (Exhibit No. 10.15. to Form 10-K Annual
Report for 2000.)
10.16.(2) Employment Agreement between the Company and Charles B. Stanley
effective January 31, 2002 and First Amendment to such Agreement.
21. Subsidiary Information.
23. Consent of Independent Auditors.
24. Power of Attorney.
99.1. Undertakings for Registration Statements on Form S-3 (No. 33-48168)
and on Form S-8 (Nos. 33-4436, 33-15149, 33-40800, 33-40801,
33-48169, 333-04913, and 333-04951).
</Table>
- ----------
* Exhibits so marked have been filed with the Securities and Exchange
Commission as part of the indicated filing and are incorporated
herein by reference.
(1) The name of the Rights Agent has been changed to U. S. Bank National
Association.
(2) Exhibit so marked is management contract or compensation plan or
arrangement.
(b) The Company did not file any Current Reports on Form 8-K during the
last quarter of 2001.