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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, 2000 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. 0-30321
QUESTAR MARKET RESOURCES, INC.
(Exact name of registrant as specified in its charter)
State of Utah 87-0287750
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
180 East 100 South, P.O. Box 45601, Salt Lake City, Utah 84145-0601
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (801) 324-2600
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock, $1.00 Par Value
SECURITIES REGISTERED PURSUANT TO THE SECURITIES ACT OF 1933:
7 1/2% Notes Due 2011
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
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of March 1, 2001. $0.
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of March 1, 2001.
4,309,427 shares of Common Stock, $1.00 par value. (All shares are
owned by Questar Corporation.)
Registrant meets the conditions set forth in General
Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing
this Form 10-K Report with the reduced disclosure format.
TABLE OF CONTENTS
Heading Page
PART I
Item 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . . . . 1
General. . . . . . . . . . . . . . . . . . . . . . . . . . 1
Oil and Gas Exploration and Production - Questar E&P,
Celsius, and Canor . . . . . . . . . . . . . . . . . .. . . 3
Development and Production - Wexpro Company. . . . . . . . . 3
Gathering, Processing and Marketing - Questar Gas Management
and Questar Energy Trading. .. . . . . . . . . . . . . .. . 4
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . 6
Competition and Customers. . . . . . . . . . . . . . . . . . 7
Relationships with Affiliates. . . . . . . . . . . . . . . . 7
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . . . . 7
Item 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . . . . 14
Item 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS.. . . . . . . . . . . . . . . . . . . . . 15
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS .. . . . . . . . . . . . . 15
Item 6. (Omitted). . . . . . . . . . . . . . . . . . . . . . . . . 15
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATION. . . . . . . 16
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK. . . . . . . . . . . . . . . . . . . . . . . . 20
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA. . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Item 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE. . . . . . . . . . . . . . . . . . . . 22
PART III
Items
10-13. (Omitted). . . . . . . . . . . . . . . . . . . . . . . . . 22
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . 22
GLOSSARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .50
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
FORM 10-K
ANNUAL REPORT, 2000
PART I
ITEM 1. BUSINESS.
General
Questar Market Resources, Inc. (the "Company or QMR;" this
reference shall include the Company's wholly-owned subsidiaries) is
a wholly-owned subsidiary of Questar Corporation ("Questar"), which
is a publicly traded and diversified energy services company.
Questar has two principal business units--Regulated Services and
Market Resources. QMR and its subsidiaries comprise the Market
Resources unit of Questar and engage in oil and gas exploration,
development and production; gas gathering and processing; wholesale
gas, electricity and hydrocarbon liquids trading. In conjunction
with its production activities, QMR also acquires producing oil and
gas properties.
As noted in the following chart, QMR itself is a subholding
company that conducts its activities through Questar Exploration and
Production Company ("Questar E&P") and its Canadian subsidiaries,
Celsius Energy Resources, Ltd. ("Celsius") and Canor Energy Ltd.
("Canor"); Wexpro Company ("Wexpro"); Questar Gas Management Company
("Questar Gas Management") and Questar Energy Trading Company
("Questar Energy Trading").
Questar Corporation
Questar InfoComm , Inc. (Information Services)
QUESTAR MARKET RESOURCES, INC. (Subholding Company)
Wexpro Company (Manages and Develops Cost-of-Service
Properties for Questar Gas)
Questar Exploration and Production Company (Exploration
and Production)
Celsius Energy Resources Ltd. and Canor Energy Ltd.
(Exploration & Production - Canada)
Questar Energy Trading Company (Wholesale Energy Marketing
and Storage)
Questar Gas Management Company (Gathering and Processing)
Questar Regulated Services Company (Subholding Company)
Questar Gas Company (Retail Distribution)
Questar Pipeline Company (Transportation and Storage)
QMR is the primary growth area within Questar's business
strategy. Questar expects to spend 60-70 percent of its capital
budget funds over the next five years on non-regulated activities,
primarily within QMR, to expand reserves through drilling and
acquisitions and to enlarge its infrastructure of gathering systems,
processing plants, header facilities, and non-regulated storage
facilities. Management of QMR believes that the diversity of the
activities pursued by QMR enhances its basic strategy to pursue
complementary growth. As the exploration and production companies
find or acquire new reserves, Questar Gas Management should have
more opportunities to expand gathering and processing activities,
and Questar Energy Trading should have more physical production to
support its marketing programs.
Business Strategy. QMR has the following strategies in its
business:
- achieve a prudent, disciplined program to grow reserves;
- provide stakeholder value performance in both the short
and long term;
- employ hedging and other risk management tools to manage
cyclicality;
- maintain a strong balance sheet that permits prudent
growth opportunities;
- maintain a portfolio of quality drilling prospects;
- identify and divest non-core and marginal assets and
activities;
- proactively avoid litigation risks; and
- employ technology and proven innovations to reduce costs.
QMR's activities are described below:
Oil and Gas Exploration and Production - Questar E&P, Celsius, and
Canor:
Questar's E&P group consists of Questar E&P and its Canadian
subsidiaries Celsius and Canor. These entities form a unique E&P
group that conducts a blended program of low-cost development
drilling, low-risk reserve acquisition, and high-quality
exploration.
The E&P group also maintains a geographical balance and
diversity, while concentrating its activities in core areas where it
has accumulated geological knowledge and has significant expertise.
Core areas of activity include the Rocky Mountain region of Wyoming
and Colorado; the Midcontinent region of 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 2000, the Company had proved reserves
(excluding cost-of-service reserves belonging to its affiliate
Questar Gas Company ("Questar Gas")) of 639.9 billion cubic feet
("Bcf") of gas and 15.0 million barrels ("MMBbls") of oil and
natural gas liquids, compared to 514.5 Bcf of gas and 13.9 MMBbls of
oil as of the same date in 1999. (Any references to oil in this
Report include natural gas liquids.) On an energy-equivalent basis
ratio of six thousand cubic feet ("Mcf") of natural gas to one
barrel ("Bbl") of crude oil, natural gas comprised approximately
87.6 percent of total regulated proved reserves. Proved developed
reserves constituted 77.6 percent of the total non-regulated proved
reserves reported. Approximately 9.4 percent of the group's natural
gas proved reserves and 24.7 percent of its oil proved reserves are
located in Canada. See Note 10 of the Notes to Consolidated
Financial Statements under Item 14 of this Report for additional
information concerning QMR's reserves. See "Glossary of Commonly
Used Oil and Gas Terms" on page __ of this Report.
Development and Production - Wexpro Company
QMR conducts development drilling and provides production
services to Questar Gas through Wexpro. 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. A summary of the Wexpro
settlement agreement is contained in Note 8 of the Notes to
Consolidated Financial Statements under Item No. 14 of this Report.
Ownership of Wexpro was moved from Questar Gas to QMR in 1982.
Wexpro, unlike 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.
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 19.5 percent
on an after-tax basis in 2000 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 2000, Wexpro's
investment (net of deferred income taxes) in cost-of-service
operations was $124.8 million compared to $108.9 million at
year-end 1999. 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 48 percent of
Questar Gas's system requirements during 2000. Questar Gas relies
upon Wexpro's drilling program to develop the properties from which
the cost-of-service gas is produced. During 2000, the average
wellhead cost of Questar Gas's cost-of-service gas was $1.78 per
decatherm ("Dth"), which is 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 2000, produced 45.0
billion cubic feet equivalent ("Bcfe") of natural gas and
hydrocarbon liquids from Questar Gas's cost-of-service properties
and added reserves of 71.3 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.)
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.
Gathering, Processing and Marketing - Questar Gas Management and
Questar Energy Trading:
Questar Gas Management 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. Questar Gas Management's core system and activities,
however, reflect its historical connection to Questar Pipeline's
regulated activities.
Questar Gas Management was formed in 1993 as a wholly-owned
subsidiary of Questar Pipeline to construct and operate the Blacks
Fork processing plant in southwestern Wyoming. It expanded in 1996
as a result of receiving Questar Pipeline's gathering assets and
activities. In mid -1996, Questar Gas Management was moved from
Regulated Services to QMR shortly after the transfer of gathering
assets and acquired the processing plants that formerly belonged to
Questar E&P.
Questar Gas Management's gathering system was originally built
as part of a regulated enterprise. It consists of 1,284 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, Questar Gas Management is obligated to gather the
cost-of-service production for the life of the properties. During
2000, Questar Gas Management gathered 36.8 million decatherms
("MMDth") of natural gas for Questar Gas, compared to 32.1 million
in 1999, for which it received $8.5 million, including $4.5 million
in demand charges.
Questar Gas Management continues to expand the volumes of gas
gathered for affiliates within QMR and for nonaffiliated customers.
During 2000, Questar Gas Management gathered 25.0 MMDth for QMR
affiliates, compared to 19.6 MMDth in 1999, and gathered 93.0 MMDth
for nonaffiliated customers, compared to 85.0 MMDth in 1999.
Questar Gas Management is interested in acquiring the existing
gathering system for the Pinedale wells and constructing additional
facilities in the area.
In addition to gathering activities, Questar Gas management is
involved in processing activities. It 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. 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 take advantage of historical price advantages for
natural gas liquids when compared to natural gas volumes. Questar
Gas Management and Wexpro jointly own a processing facility located
in the Canyon Creek area of southwestern Wyoming that has an
operating capacity of 43 MMcf per day. It owns interests in other
processing plants in the Rocky Mountain and Midcontinent areas.
Questar Gas Management's 2000 increase in gathering activities
reflects the increased value of natural gas volumes. It also
processed more natural gas liquids during 2000 in response to their
increased value, but plant volumes slowed significantly in the last
months of 2000 as natural gas became disproportionately valuable
when compared to natural gas liquids.
Questar Energy Trading conducts energy marketing activities.
It combines gas volumes purchased from third parties and equity
production (production that is produced by affiliates) to build a
flexible and reliable portfolio. Questar Energy Trading aggregates
supplies of natural gas for delivery to large customers, including
industrial users, municipalities, and other marketing entities.
During 2000, the Company marketed a total of 100.6 MMDth of natural
gas and .8 MMBbls of liquids and earned a margin of $.095 per
equivalent Dth. (The volumes and margins exclude affiliated
production.)
Questar Energy Trading uses derivatives as a risk management
tool to provide price protection for physical transactions involving
equity production (equity production is a term that refers to
production owned by QMR subsidiaries) and marketing transactions.
It executed hedges for equity production on behalf of Questar E&P
with a variety of contracts for different periods of time. Questar
Energy Trading does not engage in speculative hedging transactions.
As a wholesale marketing entity, Questar Energy Trading
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.
Questar Energy Trading is expanding its capabilities in order
to sustain its activities in an increasingly competitive environment
in which parties are becoming more sophisticated. During 2000, it,
through a limited liability company, commenced operating a private
storage facility the Clear Creek project in southwestern Wyoming
adjacent to several interstate pipelines. The storage reservoir has
a working gas capacity of 4 Bcf.
Regulation
The Company'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; submitting 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 matters, including the regulation of the size of
drilling and spacing units or proration unites, the number of wells
that may be drilled in a unit, and the unitization or pooling 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, the impose certain 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 financial 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.
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. The Company's competitors
include multinational energy companies and other independent
producers, many of which have greater financial resources than QMR has.
The Company'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 the Company's operations.
The Company 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.
Questar E&P maintains regional offices in Denver, Colorado and
Tulsa and Oklahoma City in Oklahoma. Canadian operations are
managed through an office in Calgary, Alberta.
Relationships with Affiliates
The subsidiaries of QMR have important relationships with
their affiliates as described above. Questar provides certain
administrative services, e.g., public and government relations,
financial and audit, to QMR and other members of the consolidated
group. Questar also sponsors the qualified and welfare plans in
which QMR's employees participate. Each of the Company's
subsidiaries is responsible for a proportionate share of the costs
associated with these services and benefit plans.
Employees
As of December 31, 2000, QMR had 412 employees in the United
States and 13 leased employees in Canada. None of these employees is
represented under collective bargaining agreements. Employee
relations are generally deemed to be satisfactory. QMR also
periodically engages independent consulting petroleum engineers,
environmental professionals, geologists, geophysicists, landmen and
attorneys on a fee basis.
ITEM 2. PROPERTIES.
Reserves. The following table sets forth the Company's
estimated proved reserves, the 10 percent present value of the
estimated future net revenues from the reserves and the standardized
measure of discounted net cash flows as of December 31, 2000. QMR's
reserves were estimated by Ryder Scott Company; H. J. Gruy and
Associates, Inc.; Netherland, Sewell & Associates, Inc.; Malkewicz
Hueni Associates, Inc.; Gilbert Laustsen Jung Associates Ltd.; and
Sproule Associates, Ltd., independent petroleum engineers. The
Company does not have any long-term supply contracts with foreign
governments, or reserves of equity investees or of subsidiaries with
a significant minority interest. These proved reserve volumes do
not include cost-of-service reserves managed and developed by Wexpro
for Questar Gas.
December 31, 2000
United States Canada Total
Estimated proved reserves
Natural gas (Bcf) 579.8 60.1 639.9
Oil and NGL (MMBbls) 11.3 3.7 15.0
Proved developed reserves (Bcfe) 492.3 74.1 566.4
Present value of estimated future net
revenues before future income taxes
discounted at 10% (in thousands) (1) $2,348,638 $275,436 $2,624,074
Standardized measure of discounted net cash
flows (in thousands) (2) $1,542,204 $149,417 $1,691,621
__________
(1) Estimated future net revenue represents
estimated future gross revenue to be generated
from the production of proved reserves, net of
estimated production and development costs
(but excluding the effects of general and
administrative expenses; debt service;
depreciation, depletion and amortization; and
income tax expense).
(2) The standardized measure of discounted net cash
flows prepared by the Company represent the present
value of estimated future net revenues after income
taxes, discounted at 10 percent.
Estimates of the Company's proved reserves and future net
revenues are made using sales prices estimated to be in effect as
of the date of such reserve estimates and are held constant
throughout the life of the properties (except to the extent a
contract specifically provides for escalation). Estimated
quantities of proved reserves and future net revenues are
affected by natural gas and oil prices, which have fluctuated
widely in recent years. There are numerous uncertainties
inherent in estimating natural gas and oil reserves and their
estimated values, including many factors beyond the control of
the producer. The reserve data set forth in this document
represent estimates.
Reference should be made to Note 10 of the Notes to
Consolidated Financial Statements included in Item 14 of this
Report for additional information pertaining to the Company's
proved natural gas and oil reserves as of the end of each of the
last three years.
During 2000, the Company filed estimated reserves as of
year-end of Form EIA-23 with the Energy Information
Administration in the Department of Energy and will submit a
comparable report for 2000. Although QMR uses the same technical
and economic assumption when it prepares the EIA-23, it is
obligated to report reserves for wells it operates, not for all
wells in which it has an interest, and to include the reserves
attributable to other owners in such wells.
The following charts illustrate QMR's reserve statistics
for the years ended December 31, 1996 through 2000:
Oil and Gas Reserves (Bcfe)*
Year Year-End Reserves Annual Production Reserve Life (Years)
1996 493.6 51.5 9.6
1997 469.3 61.7 7.6
1998 574.1 65.3 8.8
1999 597.6 76.6 7.8
2000 730.1 82.3 8.9
*Does not include cost of service reserves managed and developed
by Wexpro for Questar Gas.
Proportion of Proved Developed to Proved Reserves
and Proportion of Gas Reserves (Bcfe)*
Year Total Proved Proved Developed Developed Natural Gas
Reserves Reserves Percent of Total Percentage of
Proved Reserves
1996 493.6 410.1 83% 78%
1997 469.3 392.9 84% 81%
1998 574.1 506.0 88% 85%
1999 597.6 503.9 84% 86%
2000 730.1 566.4 78% 88%
*Does not include cost of service reserves managed and developed
by Wexpro for Questar Gas.
Geographic Diversity of Producing Properties:
The following table summarizes proved reserves by the Company's
major operating areas at December 31, 2000:
Proved Reserves* % of Total
(Bcfe)
Mid-Continent 325.6 45%
Rocky Mountain Region (exclusive
of Pinedale) 175.9 24%
Pinedale Anticline 146.2 20%
Western Canada 82.4 11%
*Does not include cost of service reserves managed and developed
by Wexpro for Questar Gas.
Production. The following table sets forth the Company's
net production volumes, the average sales prices per Mcf of gas,
Bbl of oil and Bbl of natural gas liquids produced, and the
production cost per Mcfe for the years ended December 31, 2000,
1999, and 1998, respectively:
Year Ended December 31,
2000 1999 1998
United States (excluding cost of
service activities)
Volumes produced and sold
Gas (Bcf) 61.7 59.8 48.6
Oil and NGL (MMBbls) 1.5 1.9 1.9
Sales Prices:
Gas (per Mcf) $ 2.80 $ 2.02 $ 1.95
Oil and NGL (per Bbl) $19.61 $13.31 $12.41
Production costs per Mcfe $ .69 $ .59 $ .64
Canada
Volumes produced and sold
Gas (Bcf) 7.3 2.9 2.7
Oil and NGL (MMBbls) .7 0.4 0.4
Sales Prices:
Gas (per Mcf) $ 2.83 $ 1.61 $ 1.40
Oil and NGL (per Bbl) $22.29 $16.56 $14.09
Production costs per Mcfe $ .73 $ .67 $ .58
Productive Wells. The following table summarizes the
Company's productive wells as of December 31, 2000:
Productive Wells (1) (2)
Gas Wells Oil Wells Total Wells
Gross Net Gross Net Gross Net
United States 3,702 1,554 1,046 401 4,748 1,955
Canada 542 187 202 67 744 254
Total: 4,244 1,741 1,248 468 5,492 2,209
(1) Although many of the Company's wells produce
both oil and gas, a well is categorized as
either an oil well or a gas well based upon the
ratio of oil to gas production.
(2) Each well completed to more than one producing zone is
counted as a single well. There were 140 gross wells
with multiple completions.
The Company also held numerous overriding royalty interests
in gas and oil wells, a portion of which are convertible to
working interests after recovery of certain costs by third
parties. After converting to working interests, these overriding
royalty interests will be included in the Company's gross and net
well count.
Leasehold Acreage. The following table summarizes
developed and undeveloped leasehold acreage in which the Company
owns a working interest as of December 31, 2000. "Undeveloped
Acreage" includes (i) leasehold interests that already may have
been classified as containing proved undeveloped reserves; and
(ii) unleased mineral interest acreage owned by the Company.
Excluded from the table is acreage in which the Company's
interest is limited to royalty, overriding royalty, and other
similar interests.
Leasehold Acreage - December 31, 2000
Developed (1) Undeveloped (2) Total
Gross Net Gross Net Gross Net
United States
Arizona - - 480 450 480 450
Arkansas 37,729 16,569 1,230 373 38,959 16,942
California 760 265 23,102 9,043 23,862 9,308
Colorado 176,651 125,297 207,581 104,852 384,232 230,149
Idaho - - 44,175 10,643 44,175 10,643
Illinois 172 39 14,307 3,997 14,479 4,036
Indiana - - 1,621 467 1,621 467
Kansas 134 134 44,330 16,430 44,464 16,564
Kentucky - - 14,461 5,468 14,461 5,468
Louisiana 15,246 9,992 404 397 15,650 10,389
Michigan - - 6,200 1,266 6,200 1,266
Minnesota - - 313 104 313 104
Mississippi 25,706 21,408 859 273 26,565 21,681
Montana 25,285 10,187 319,745 58,594 345,030 68,781
Nevada 320 280 680 543 1,000 823
New Mexico 90,297 66,349 32,006 9,553 122,303 75,902
North Dakota 1,333 375 145,841 21,580 147,174 21,955
Ohio - - 202 43 202 43
Oklahoma 1,538,294 290,246 52,736 33,296 1,591,030 323,542
Oregon - - 43,869 7,671 43,869 7,671
South Dakota - - 204,558 107,988 204,558 107,988
Texas 168,336 61,000 51,881 40,725 220,217 101,725
Utah 45,712 35,001 109,180 43,280 154,892 78,281
Washington - - 26,631 10,149 26,631 10,149
West Virginia 969 115 - - 969 115
Wyoming 221,718 142,625 447,233 268,848 668,951 411,473
Total
U.S. 2,348,662 779,882 1,793,625 756,033 4,142,287 1,535,915
Canada
Alberta 222,938 82,919 324,636 135,474 547,574 218,393
British
Columbia 33,069 8,485 42,108 21,719 75,177 30,204
Saskatchewan 2,277 1,061 4,625 4,462 6,902 5,523
Total
Canada 258,284 92,465 371,369 161,655 629,653 254,120
Total
Acreage 2,606,946 872,347 2,164,994 917,688 4,771,940 1,790,035
________
(1) Developed acres are acres spaced or assignable to
productive wells.
(2) Undeveloped acreage is leased acreage on which wells
have not been drilled or completed to a point that would
permit the production of commercial quantities of
natural gas and oil regardless of whether such acreage
contains proved reserves. Of the aggregate 2,164,994
gross and 917,688 net undeveloped acres, 114,827 gross
and 30,747 net acres are held by production from other
leasehold acreage.
Substantially all the leases summarized in the preceding
table will expire at the end of their respective primary terms
unless the existing leases are renewed or production has been
obtained from the acreage subject to the lease prior to that
date, in which event the lease will remain in effect until the
cessation of production. The following table sets forth the
gross and net acres subject to leases summarized in the preceding
table that will expire during the periods indicated:
Acres Expiring
Gross Net
Twelve Months Ending
December 31, 2001 154,070 58,641
December 31, 2002 88,980 44,787
December 31, 2003 141,354 62,639
December 31, 2004 74,890 49,327
December 31, 2005 and later 1,705,700 702,294
Drilling Activity. The following table summarizes the number
of development and exploratory wells drilled by the Company,
including the cost-of-service wells drilled by Wexpro, during the
years indicated.
Year Ended December 31,
2000 1999 1998
Gross Net Gross Net Gross Net
Development Wells
United States
Completed as natural
gas wells 211 79.8 159 78.4 105 54.6
Completed as oil wells 9 1.4 5 2.4 29 1.0
Dry holes 12 5.0 15 6.1 12 3.7
Waiting on completion 36 - 29 - 13 -
Drilling 14 - 6 - 9 -
Canada
Competed as natural
gas wells 11 1.1 7 1.2 4 0.9
Completed as oil wells 8 2.3 5 1.9 12 4.0
Dry holes 2 1.1 2 1.3 4 1.2
Waiting on completion 2 - 2 - 2 -
Drilling 1 - - - 1 -
Total Development Wells 306 90.7 230 91.3 191 65.4
Exploratory Wells
United States
Completed as natural
gas wells - - 1 0.2 5 1.6
Completed as oil wells - - - - 1 6
Dry holes 5 2.0 2 1.1 4 1.4
Waiting on completion - - 1 - - -
Drilling 1 - 1 - - -
Canada
Competed as natural
gas wells 1 .2 - - - -
Completed as oil wells 1 .2 - - 1 .3
Dry holes 2 .9 - - 3 1.4
Waiting on completion - - - - - -
Total Exploratory Wells 10 3.3 5 1.3 14 5.3
Total Wells 316 94.0 235 92.6 205 70.7
Operation of Properties. The day-to-day operations of oil
and gas properties are the responsibility of an operator
designated under pooling or operating agreements. The operator
supervises production, maintains production records, employs
field personnel and performs other functions. The charges under
operating agreements customarily vary with the depth and location
of the well being operated.
QMR is the operator of approximately 50 percent of its
wells. As operator, QMR receives reimbursement for direct
expenses incurred in the performance of its duties as well as
monthly per-well producing and drilling overhead reimbursement at
rates customarily charged in the area to or by unaffiliated third
parties. In presenting its financial data, QMR records the
monthly overhead reimbursement as a reduction of general and
administrative expense, which is a common industry practice.
Title to Properties. Title to properties is subject to
royalty, overriding royalty, carried, net profits, working and
other similar interests and contractual arrangements customary in
the oil and gas industry, liens for current taxes not yet due
and, in some instances, to other encumbrances. The Company
believes that such burdens do not materially detract from the
value of such properties or from the respective interests therein
or materially interfere with their use in the operation of the
business.
As is customary in the industry in the case of undeveloped
properties, little investigation of record title is made at the
time of acquisition (other than a preliminary review of local
records). Investigations, generally including a title opinion of
outside counsel, are made prior to the consummation of an
acquisition of producing properties and before commencement of
drilling operations on undeveloped properties.
Pinedale. Both Questar E&P and Wexpro are involved in
Pinedale drilling. During 2000, Questar E&P and Wexpro drilled
nine wells and completed six of them in the Pinedale Anticline
area of Sublette County, Wyoming. (Three of the wells will not
be completed until June of 2001 when winter drilling restrictions
are lifted.) Drilling results and initial production tests
confirmed reserve expectations of 5-6 Bcf per well. As of
December 31, 2000, gross daily production from 14 Company-owned
wells was estimated at 26 MMcf and 45 Bbl of oil.
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 and expect to drill between 135-150 wells based on
80-acre spacing.
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.
Since the gas reserves are contained in tight sands with a low
porosity, Questar E&P and Wexpro did not drill additional wells
in the Pinedale 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 cost an average
of $2.2 million to drill and complete; this cost reflects the
completion depth of the wells (12,848 to 13,300 feet), the need
for special handling and multiple stimulations, and government
regulations that impose pad limitations and restrict drilling.
Current production profiles suggest that the average well may
produce on a long-term basis after stabilizing between 2 and 4
MMcf per day within the first year or two after completion.
Questar E&P and Wexpro expect to continue drilling in the
Pinedale area during the next several years.
ITEM 3. LEGAL PROCEEDINGS.
There are various legal proceedings pending against QMR.
Significant cases are discussed below.
BRIDENSTINE. On January 4, 2001, a district court judge in
Oklahoma approved the settlement agreement in Bridenstine v.
Kaiser-Francis Oil Company, a class action lawsuit that was
originally filed against Questar E&P, other named affiliates
including Questar and QMR, and unrelated defendants in 1995.
Pursuant to the terms of the settlement, Questar E&P and Union
Pacific Resources Company (predecessor in interest to Questar
E&P) paid $22.5 million, with Questar E&P's portion being $16.5
million. Although the Questar defendants disputed claims that
centered on allegations of an excessive and improper
transportation charged against royalty payments, they settled the
lawsuit to avoid continued legal costs and the uncertainty of a
jury verdict.
GRYNBERG. Questar affiliates, including Questar E&P are
named defendants in a lawsuit filed by an independent producer
(Grynberg) under the Federal False Claims Act. This case and the
75 substantially similar cases filed by Grynberg against
pipelines and their affiliates have 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 has not ruled on the defendants' motion to dismiss.
On March 8, 2001, the trial court judge granted a motion to
dismiss the lawsuit filed by Grynberg against several Questar
defendants including Questar Gas Management, Questar Energy
Trading and Questar Pipeline. This case, which was filed in a
Utah state district court, claims that the Questar defendants
mismeasured gas volumes attributable to Mr. Grynberg's working
interest in a specified property in southwestern Wyoming. The
plaintiff's allegations included breach of contract, negligent
misrepresentation, fraud, breach of fiduciary duty, etc. The
judge dismissed the lawsuit based on defendants' arguments that
the applicable statute of limitation had expired and there was no
basis to support fraudulent concealment claims, or independent
tort claims.
QUINQUE. Questar E&P, Questar Gas Management, Wexpro and
other Questar affiliates are among the 220 named defendants in
Quinque Operating Company v. Gas Pipelines, which was recently
transferred from the Wyoming federal district court where it had
been consolidated with the Grynberg cases to the Kansas state
court where it had been originally filed. This case is very
similar to the cases filed by Mr. Grynberg against the pipeline
industry, but the allegations of 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.
Royalty class actions are being asserted in numerous
states, including Wyoming, against other companies in the oil and
gas production and marketing businesses in which QMR's
subsidiaries participate. Similar actions could be filed against
the Company.
There are various other legal proceedings against
subsidiaries of QMR. While it is not currently possible to
predict or determine the outcome of these proceedings, it is the
opinion of management that the outcome will not have a materially
adverse effect on the Company's results of operations, financial
position or liquidity.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
The Company did not submit any matters to a vote of its
stockholder during the last quarter of 2000.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
All of the Company's outstanding shares of common stock,
$1.00 par value, are owned by Questar. Information concerning
the dividends paid on such stock and the ability to pay dividends
is reported in the Statements of Common Shareholder's Equity and
the Notes to Financial Statements included in Item 14 of this
Report.
ITEM 6. SELECTED FINANCIAL DATA.
The Company, as the wholly-owned subsidiary of a reporting
company under the Securities and Exchange Act of 1934 (the
"Act"), is entitled to omit the information requested in this Item.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
RESULTS OF OPERATIONS
QUESTAR MARKET RESOURCES ("QMR" or "Market Resources" or the
"Company") conducts exploration and production, gas development,
gathering, processing and marketing activities. Following is a
summary of financial results and operating information.
Year Ended December 31,
2000 1999 1998
(In Thousands)
OPERATING INCOME
Revenues
Natural gas sales $ 193,359 $ 125,245 $ 98,767
Oil and natural gas liquids sales 59,901 41,521 36,722
Cost-of-service gas operations 74,492 61,705 61,448
Energy marketing 379,760 243,296 234,565
Gas gathering and processing 29,278 22,341 21,954
Other 5,263 4,203 4,816
Total revenues 742,053 498,311 458,272
Operating expenses
Energy purchases 369,752 239,201 230,462
Operating and maintenance 106,703 79,916 73,763
Depreciation and amortization 84,475 78,608 71,377
Write-down of full cost oil
and gas properties 31,000
Other taxes 36,262 21,516 24,988
Wexpro settlement agreement -
oil income sharing 4,758 2,292 1,053
Total operating expenses 601,950 421,533 432,643
Operating income $ 140,103 $ 76,778 $ 25,629
OPERATING STATISTICS
Production volumes
Natural gas (in MMcf) 68,963 62,712 51,309
Oil and natural gas liquids (in Mbbl)
Questar Exploration & Production 2,225 2,311 2,340
Wexpro 521 555 554
Production revenue
Natural gas (per Mcf) $ 2.80 $ 2.00 $ 1.92
Oil and natural gas liquids (per bbl)
Questar Exploration & Production $ 20.50 $ 13.92 $ 12.70
Wexpro $ 27.43 $ 16.84 $ 12.64
Wexpro investment base, net
of deferred income taxes
(in millions) $ 124.8 $ 108.9 $ 97.6
Energy-marketing volumes
(in thousands of equivalent dth) 105,632 112,982 113,513
Natural gas-gathering volumes (in Mdth)
For unaffiliated customers 92,969 84,961 72,908
For Questar Gas 36,791 32,050 29,893
For other affiliated customers 25,068 19,659 17,720
Total gathering 154,828 136,670 120,521
Gathering revenue (per dth) $ 0.13 $ 0.15 $ 0.16
Revenues
Revenues were 49% higher in 2000 when compared with 1999 because
of higher prices for natural gas, oil and NGL and increased
natural gas production. Natural gas production rose 10% to 69
Bcf and the average selling price increased 40%. U. S. gas
production increased 3% to 61.7 Bcf, while Canadian production
rose 152% to 7.3 Bcf. Questar acquired Canadian reserves and
producing properties in January 2000. Approximately 53% of gas
production in 2000 was hedged at an average price of $2.16 per
Mcf, net to the well. Hedging activities reduced revenues from
gas sales by $33.7 million in 2000, but had an insignificant
impact in 1999 and 1998.
Selling prices of oil and NGL for nonregulated operations
increased 47% to a combined average of $20.50 per barrel and more
than offset a 4% decrease in production volumes. Approximately
73% of the nonregulated oil production was hedged at an average
price of $17.36 per barrel. Hedging activities reduced revenues
from oil sales by $15.5 million in 2000, but had an insignificant
impact in 1999 and 1998. Production declined in 2000 as a result
of selling nonstrategic properties in the fourth quarter of 1999.
For 2001, Questar has used swaps, costless collars and fixed
price contracts to hedge approximately 55% of estimated gas
production based on December 2000 reserves. The average hedged
price is $2.90 per Mcf (net to the well) assuming floor prices on
collars. The average hedged price increases to $3.15 per Mcf
(net to the well) if collar ceiling prices are assumed.
Approximately 62% of 2001 estimated oil production, based on
December 2000 reserves, is hedged at an average price of $17.20
per barrel, net to the well. Quantities of hedged production in
any given month range between 49% and 66% for gas and 56% and 70%
for oil.
Revenues from cost-of-service operations were 21% higher in 2000
compared with 1999. Wexpro manages and develops oil and natural
gas properties on behalf of Questar Gas and receives a return on
its investment in successful wells. The natural gas production is
delivered to Questar Gas at 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 divided
between Wexpro and Questar Gas. Questar Gas's portion is reported
as oil-income sharing. Wexpro's investment base, net of deferred
income taxes, grew 15% in 2000 when compared with 1999. The
average return on investment was 19.5% in 2000 and 20% in 1999.
Higher energy prices were responsible for substantial increases
in revenues for energy marketing and improved plant-processing
margins. Increased gas demand led to higher volumes of gas
gathering.
Revenues in 1999 improved 9% compared with 1998 as a result of
increased prices for gas, oil and NGL and a 22% rise in gas
production. Natural gas selling prices averaged 4% higher in
1999.
Operating Expenses
Operating and maintenance expenses were 34% higher in 2000
primarily due to an increase in the number of gas and oil
properties and increased legal costs in the settlement of a major
case. Depreciation and amortization expense increased 7% in 2000
due largely to a 10% improvement in natural gas production. The
combined U.S. and Canadian full-cost amortization rate was $.79
per thousand cubic feet equivalent (Mcfe) for 2000, down from
$.80 per Mcfe in 1999. Other taxes, primarily production
related, rose 69% in 2000 driven by higher revenues and prices.
Interest and other income
Interest and other income was higher in 2000 due to a $3.9
million pre-tax gain from selling securities available for sale,
recording capitalized financing costs associated with an
underground storage project of $1.9 million and $1.4 million of
interest earned on qualifying hedging collateral. Sales of
securities available for sale generated a $.4 million pre-tax
gain in 1999.
Debt expense
Interest expense increased due to higher short- and long-term
borrowing and to higher interest rates in 2000.
Income taxes
The effective combined federal, state and foreign income tax rate
was 34.9% in 2000 and 28.8% in 1999. Income tax rates were below
the combined statutory rate of about 40% primarily due to
nonconventional fuel credits, which amounted to $4.7 million in
2000, $5.3 million in 1999 and $5.7 million in 1998.
Nonregulated Gas and Oil Reserves
Market Resources achieved a 261% reserve replacement ratio in
2000 compared with 131% in 1999. Reserve additions, revisions and
purchases, net of sales in place, amounted to 214.8 Bcfe in 2000,
more than double the 100.1 Bcfe added in 1999. Gains in reserves
occurred through drilling results in the Pinedale Anticline and
the acquisition of 61.1 Bcfe of proved reserves in Canada. In
January 2001, Market Resources closed on the sale of 290
producing properties and a gas gathering system in the
Mid-continent for $27 million with an effective sale date of
November 2000. The properties produced approximately 4.3 MMcf of
gas and 180 barrels of oil per day, but were not compatible with
the long-term strategic plans of the Company. In the fourth
quarter of 1999, Market Resources sold producing properties,
mostly in the Permian Basin and Kansas, with combined daily
production of 4.3 MMcf of gas and 1,100 barrels of oil.
Market Resources achieved a five-year average finding cost of
$.86 per Mcfe, excluding cost-of-service operations, in 2000
compared with $.90 per Mcfe in 1999.
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities
Year Ended December 31,
2000 1999 1998
(In Thousands)
Net income $85,042 $45,866 $16,162
Adjustments to net income 108,758 90,077 99,543
Changes in operating assets
and liabilities (54,680) 4,914 11,808
Net cash provided from
operating activities $139,120 $140,857 $127,513
Net cash provided from operating activities decreased 1% in 2000
when compared with 1999 due to timing differences in accounts
receivable more than offsetting an 85% increase in net income.
The balances in accounts receivable and qualifying hedging
accounts increased as a result of higher energy prices. This was
partially offset by increases in accounts payable caused by
higher energy prices. The asset write-down in 1998 and the effect
on deferred income taxes were noncash transactions.
Investing Activities
Capital expenditures in 2000 primarily reflected exploration for
and development of gas and oil reserves and a purchase of a
Canadian company with 61.1 Bcfe of proved reserves. Market
Resources participated in drilling 316 wells (94 net wells) in
2000 that resulted in 223 gas wells, 18 oil wells, 21 dry holes
and 54 wells in progress at year end. The success rate was 92%.
The details of capital expenditures for 2000, 1999 and a forecast
of 2001 were as follows:
Year Ended December 31,
2001
Forecast 2000 1999
(In Thousands)
Exploratory drilling $8,700 $752 $1,538
Development drilling 76,000 97,361 64,642
Other exploration 10,700 8,647 19,464
Reserve acquisitions 32,000 65,130 3,704
Production 5,100 8,382 8,746
Gathering and processing 28,000 3,330 12,705
Electric generation 25,000
Storage 7,100 11,513 4,108
General 1,500 855 19,362
$194,100 $195,970 $134,269
Financing Activities
Approximately 80% of the net cash used in investing activities
was supplied by net cash flow provided from operating activities.
Proceeds from short-term borrowing and cash released from an
escrow account provide the remaining sources of funding in 2000.
Proceeds from a 1999 sale of nonstrategic gas and oil properties
were placed in an escrow account pending a possible reinvestment
in other producing properties. When this did not occur, the
funds were released from escrow. A sale with similar conditions
and amounting to $27 million was finalized in January 2001.
In the third quarter of 2000, Market Resources initiated an
unrated commercial-paper program with a $100 million capacity.
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 at December 31, 2000.
On March 6, 2001, Market Resources issued in a public offering
$150 million of 7.5% notes due 2011. Market Resources applied the
proceeds of the debt offering to repay a portion of its
outstanding floating-rate debt. In 1999, Market Resources
entered into a long-term revolving-credit facility with a
syndication of banks and a $300 million capacity. Market
Resources had borrowed $244.4 million as of December 31, 2000
under this arrangement.
QMR's consolidated capital structure consisted of 35% long-term
debt and 65% common shareholder's equity at December 31, 2000.
The Company's long-term debt has been rated BBB+ by Standard and
Poor's and Baa2 by Moody's.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK.
QMR'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. QMR
also has reserved pipeline capacity for which it is obligated to
pay $3 million annually for the next six years, regardless of
whether it is able to market the capacity to others.
Hedging Policy
The Company has established policies and procedures for managing
market risks through the use of commodity-based derivative
arrangements. A primary objective of these hedging transactions
is to protect the Company's commodity sales from adverse changes
in energy prices. 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 hedging arrangements.
The Company does not enter into derivative arrangements for
speculative purposes.
Energy-Price Risk Management
Energy-price risk is a function of changes in commodity prices as
supply and demand fluctuate. Market Resources bears a majority of
the risk associated with changes in commodity prices. The
Company 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 50.5 million dth of gas and 1 million barrels of oil at
December 31, 2000. A year earlier the contracts covered 72.1
million dth of natural gas and 2.4 million barrels of oil. The
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, 2000, had terms
extending through December 2003, with about 91% of those
contracts expiring by the end of 2001.
The financial mark-to-market adjustment of gas and oil price-hedging
contracts at December 31, 2000 was a negative $98 million and
represented a liability owed to counterparties if terminated. A
10% decline in gas and oil prices would decrease the
mark-to-market adjustment by $18.1 million; while a 10% increase
in prices would increase the mark-to-market adjustment by $18.1
million. The mark-to-market adjustment of gas and oil
price-hedging contracts at December 31, 1999 was a negative $6.2
million. A 10% decline in gas and oil prices at that time would
have caused a positive mark-to-market adjustment of $16.7
million. Conversely, a 10% increase in prices would have resulted
in a $16.3 million negative mark-to-market adjustment. The
calculations used energy prices posted on the NYMEX, various
"into the pipe" postings and fixed prices for the indicated
measurement dates. These sensitivity calculations do not
consider changes in 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), which should largely offset the change in
value of the hedge contracts.
Interest-Rate Risk Management
The Company held floating-rate long-term debt at December 31,
2000 and 1999 of $244.4 million and $264.9 million, respectively.
The book value of variable-rate debt approximates fair value. If
interest rates declined by 10%, interest costs paid on
variable-rate long-term debt would decrease about $1.7 million in
2000 and 1999.
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.
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 $54.4 million
(U.S.) is expected to be repaid from future operations of the
foreign company.
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.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Company's financial statements are included in Part IV,
Item 14, herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
QMR 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
The Company, as the wholly-owned subsidiary of a reporting
company under the Act, is entitled to omit all information requested
in PART III (Items 10-13).
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 identified in the List of
Financial Statements are filed as part of this Report.
(3) Exhibits. The following is a list of exhibits required
to be filed as a part of this Report in Item 14(c).
Exhibit No. Description
3.1.* Articles of Incorporation dated April 27, 1988
for Utah Entrada Industries, Inc. (Exhibit
No. 3.1. to the Company's Form 10 dated April
12, 2000.)
3.2.* Articles of Merger, dated May 20, 1988, of
Entrada Industries, Inc., a Delaware
corporation and Utah Entrada Industries, Inc,
a Utah corporation. (Exhibit No. 3.2. to the
Company's Form 10 dated April 12, 2000.)
3.3.* Articles of Amendment dated August 31, 1998,
changing the name of Entrada Industries, Inc.
to Questar Market Resources, Inc. (Exhibit
No. 3.3. to the Company's Form 10 dated April
12, 2000.)
3.4.* Bylaws (as amended effective February 8,
2000.) (Exhibit No. 3.4. to the Company's
Form 10 dated April 12, 2000.)
4.1.* Indenture dated as of March 1, 2001, between the Questar
Market Resources, Inc. and Bank One, NA, as Trustee for
the Company's 71/2% Notes due 2011. (Exhibit No. 4.01.
to the Company's Current Report on Form 8-K dated March
6, 2001.)
4.2.* Form of 71/2% Notes due 2011. (Exhibit No. 4.02. to the
Company's Current Report on Form 8-K dated March 6, 2001.)
4.3. U.S. Credit Agreement, dated April 19, 1999,
by and among Questar Market Resources, Inc.,
as U.S. borrower, NationsBank, N.A., as U.S.
agent, and certain financial institutions, as
lenders, with the First Amendment dated May
17, 1999, the Second Amendment dated July 30,
1999, the Third Amendment dated November 30,
1999, the Fourth Amendment dated April 17,
2000, the Fifth Amendment dated October 6,
2000, and the Sixth Amendment dated February
9, 2001. (Exhibit No. 4.1. to the Company's
Form 10 dated April 12, 2000, for the U. S.
Credit Agreement, and the First, Second and
Third Amendments; Exhibit No. 4.1. to the
Company's Form 10/A dated November 9, 2000,
for the Fourth and Fifth Amendments.) The
Sixth Amendment is filed with this Report.1
4.4. Long-term debt instruments with principal amounts not
exceeding 10 percent of QMR's total consolidated assets
are not filed as exhibits. The Company will furnish a
copy of these agreements to the Commission upon request.
10.1.* Stipulation and Agreement, dated October 14, 1981,
executed by Mountain Fuel Supply Company [Questar Gas
Company]; Wexpro Company; 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 Questar Gas Company's Form 10-K Annual Report
for 1981.)
21. Subsidiary Information.
24. Power of Attorney
*Exhibits so marked have been filed with the Securities and
Exchange Commission as part of the referenced filing and are
incorporated herein by reference.
(b) The Company filed two Current Reports on Form 8-K during
the last quarter of 2000. The first report was dated November 21,
2000, and disclosed the settlement agreement in Bridenstine v.
Kaiser-Francis Oil Company. The second report was dated December 7,
2000, and contained a press release on the results of drilling at
the Pinedale Anticline area. Neither report included any financial
statements.
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, 2000
QUESTAR MARKET RESOURCES, INC.
SALT LAKE CITY, UTAH
FORM 10-K -- ITEM 14 (a) (1) AND (2)
QUESTAR MARKET RESOURCES, INC.
LIST OF FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
The following financial statements of Questar Market Resources Inc.
are included in Item 8:
Statements of income, Years ended December 31, 2000, 1999 and
1998
Balance sheets, December 31, 2000 and 1999
Statements of common shareholder's equity, Years ended
December 31, 2000, 1999 and 1998
Statements of cash flows, Years ended December 31, 2000, 1999
and 1998
Notes to financial statements
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.
Report of Independent Auditors
Board of Directors
Questar Market Resources, Inc.
We have audited the accompanying balance sheets of Questar Market
Resources, Inc. as of December 31, 2000 and 1999, and the related
statements of income and common shareholder's equity and cash flows
for each of the three years in the period ended December 31, 2000.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with 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 financial position of Questar
Market Resources, Inc. at December 31, 2000 and 1999, and the
results of its operations and its cash flows for each of the three
years in the period ended December 31, 2000, in conformity with
accounting principles generally accepted in the United States.
/s/ Ernst & Young
Ernst & Young
Salt Lake City, Utah
March 6, 2001
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
2000 1999 1998
(In Thousands)
REVENUES
From unaffiliated customers $649,200 $418,603 $382,791
From affiliates 92,853 79,708 75,481
TOTAL REVENUES 742,053 498,311 458,272
OPERATING EXPENSES
Cost of natural gas and other
products sold 369,752 239,201 230,462
Operating and maintenance 106,703 79,916 73,763
Depreciation and amortization 84,475 78,608 71,377
Write-down of full cost oil
and gas properties 31,000
Other taxes 36,262 21,516 24,988
Wexpro settlement agreement -
oil income sharing 4,758 2,292 1,053
TOTAL OPERATING EXPENSES 601,950 421,533 432,643
OPERATING INCOME 140,103 76,778 25,629
INTEREST AND OTHER INCOME 10,631 4,272 3,638
INCOME (LOSS) FROM UNCONSOLIDATED
AFFILIATES 2,776 763 (930)
DEBT EXPENSE (22,922) (17,363) (12,631)
INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 130,588 64,450 15,706
INCOME TAX EXPENSE (CREDIT) 45,546 18,584 (1,019)
INCOME FROM CONTINUING OPERATIONS 85,042 45,866 16,725
DISCONTINUED OPERATIONS, net of income
taxes of $347 (563)
NET INCOME $85,042 $45,866 $16,162
See notes to financial statements.
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2000 1999
(In Thousands)
CURRENT ASSETS
Cash and cash equivalents $ 3,980
Notes receivable from Questar Corporation $ 4,000
Accounts receivable, net of allowance of
$1,775 in 2000 and $1,350 in 1999 126,030 64,364
Accounts receivable from affiliates 17,427 11,459
Qualifying hedging collateral 48,377
Federal income taxes recoverable 4,976
Inventories, at lower of average cost or market
Gas and oil storage 7,618 8,863
Material and supplies 2,298 2,390
Prepaid expenses and other 4,828 4,452
TOTAL CURRENT ASSETS 215,534 95,528
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties - full cost accounting
Proved properties 1,082,009 943,349
Unproved properties, not being amortized 76,216 69,777
Support equipment and facilities 13,179 13,408
Cost-of-service oil and gas operations -
successful efforts accounting 348,403 318,451
Gathering, processing and marketing 137,484 124,691
1,657,291 1,469,676
Less allowances for depreciation and amortization
Oil and gas properties - full cost accounting 601,620 544,491
Cost-of-service oil and gas operations -
successful efforts accounting 193,029 180,867
Gathering, processing and marketing 58,388 53,337
853,037 778,695
NET PROPERTY, PLANT AND EQUIPMENT 804,254 690,981
INVESTMENT IN UNCONSOLIDATED
AFFILIATES 15,417 13,301
OTHER ASSETS
Cash held in escrow account 5,387 36,727
Securities available for sale 10,402
Other 4,344 952
9,731 48,081
$1,044,936 $ 847,891
LIABILITIES AND SHAREHOLDER'S EQUITY
2000 1999
(In Thousands)
CURRENT LIABILITIES
Checks outstanding in excess
of cash balances $ 1,246
Short-term loans $ 12,500
Notes payable to Questar 51,000 24,500
Accounts payable and accrued expenses
Accounts and other payables 140,254 67,385
Accounts payable to affiliates 3,761 2,952
Federal income taxes 6,232
Other taxes 19,359 14,266
Interest 951 1,443
Total accounts payable and accrued
expenses 164,325 92,278
TOTAL CURRENT LIABILITIES 227,825 118,024
LONG-TERM DEBT 244,377 264,894
DEFERRED INCOME TAXES 96,459 59,936
OTHER LIABILITIES 13,847 14,674
MINORITY INTEREST 5,483 2,529
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY
Common stock - par value $1 per share;
authorized, 25,000,000 shares; issued
and outstanding, 4,309,427 shares 4,309 4,309
Additional paid-in capital 116,027 116,027
Retained earnings 338,130 270,388
Cumulative other comprehensive loss (1,521) (2,890)
$1,044,936 $847,891
See notes to consolidated financial statements.
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
Additional Other Compre-
Common Paid-in Retained Comprehensive hensive
Stock Capital Earnings Income (loss) Income
(In Thousands)
Balance at
January 1, 1998 $4,309 $116,027 $238,955 $ (8)
1998 net income 16,162 $16,162
Cash dividends (15,900)
Foreign currency
translation
adjustment, net
of income taxes
of $53 93 93
Balance at
December 31, 1998 4,309 116,027 239,217 85 $16,255
1999 net income 45,866 45,866
Cash dividends (16,600)
Dividend of shares
of Questar Energy
Services 1,905
Unrealized loss on
securities available for
sale, net of income
taxes of $1,557 (2,515) (2,515)
Foreign currency
translation adjustment,
net of income taxes
of $284 (460) (460)
Balance at
December 31, 1999 4,309 116,027 270,388 (2,890) $42,891
2000 net income 85,042 85,042
Cash dividends (17,300)
Unrealized gain on
securities available
for sale, net of
income taxes
of $1,557 2,515 2,515
Foreign currency
translation
adjustment, net
of income taxes
of $1,018 (1,146) (1,146)
Balance at
December 31, 2000 $4,309 $116,027 $338,130 $(1,521) $86,411
See notes to financial statements.
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
2000 1999 1998
(In Thousands)
OPERATING ACTIVITIES
Net income $ 85,042 $ 45,866 $ 16,162
Adjustments to reconcile net
income to net cash provided
from operating activities
Depreciation and amortization 85,085 81,150 71,951
Deferred income taxes 29,740 9,381 (4,619)
Write-down of oil and gas properties 31,000
(Income) loss from unconsolidated
affiliates,net of cash distributions (2,117) (66) 1,211
Gain from sale of securities (3,950) (388)
Changes in operating assets
and liabilities
Accounts receivable and qualifying
hedging collateral (112,757) (2,631) 20,572
Inventories 1,337 (468) (4,996)
Prepaid expenses and other (423) (83) 555
Accounts payable and accrued expenses 74,226 5,655 (7,002)
Federal income taxes (11,207) 127 2,399
Other assets (3,125) (783) (628)
Other liabilities (2,731) 3,097 908
NET CASH PROVIDED FROM
OPERATING ACTIVITIES 139,120 140,857 127,513
INVESTING ACTIVITIES
Capital expenditures
Purchase of property, plant
and equipment (195,970) (109,405) (252,671)
Other investments (24,864) (1,875)
(195,970) (134,269) (254,546)
Proceeds from disposition of
property, plant and equipment 3,014 38,629 7,857
Proceeds from sale of securities 18,424 1,214
NET CASH USED IN INVESTING ACTIVITIES (174,532) (94,426) (246,689)
FINANCING ACTIVITIES
Decrease in notes receivable
from Questar 4,000 21,100 8,400
Change in notes payable to Questar 26,500 (97,300) 77,500
Increase in short-term debt 12,500
Change in cash in escrow 31,340 (36,727)
Checks written in excess of
cash balances (1,246) 1,246
Issuance of long-term debt 61,725 275,000 64,343
Payment of long-term debt (80,087) (195,000) (14,283)
Other financing 2,955
Payment of dividends (17,300) (16,600) (15,900)
NET CASH PROVIDED FROM (USED IN)
FINANCING ACTIVITIES 40,387 (48,281) 120,060
Foreign currency translation
adjustments (995) (44) (4)
Change in cash and cash equivalents 3,980 (1,894) 880
Beginning cash and cash equivalents 1,894 1,014
ENDING CASH AND CASH EQUIVALENTS $ 3,980 $ - $ 1,894
See notes to consolidated financial statements.
QUESTAR MARKET RESOURCES, INC. 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 Market Resources,
Inc. and subsidiaries (the "Company" or "QMR" or "Market
Resources"). The Company is a wholly-owned subsidiary of
Questar Corporation ("Questar"). QMR, through its
subsidiaries, conducts gas and oil exploration, development and
production, gas gathering and processing, and wholesale energy
marketing. Questar Exploration and Production ("Questar E &
P"), conducts exploration, development and production
activities. Wexpro Company ("Wexpro") operates and develops
producing properties on behalf of Questar Gas. Questar Gas
Management conducts gas gathering and plant processing
activities. Questar Energy Trading performs wholesale energy
marketing activities and through a 75% interest in Clear Creek
Storage Company, LLC, operates a gas-storage field. All
significant intercompany balances and transactions have been
eliminated in consolidation.
Investments in Unconsolidated Affiliates: QMR uses the equity
method to account for investment in affiliates in which it does
not have control. The Company owns a 15% interest in Canyon
Creek Compression Co., a 50% interest in Blacks Fork Gas
Processing Co. and a 15% interest in Roden Participants, Ltd.
Generally, its investment in these affiliates equals the
underlying equity in net assets.
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. The
Company uses 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. The Company's net gas imbalances at
December 31, 2000, 1999 and 1998 were not significant.
Wexpro Settlement Agreement - Oil Income Sharing: Wexpro
settlement agreement-oil income sharing represents payments
made to Questar Gas for its share of the income from oil and
NGL products associated with cost of service oil properties
pursuant to the terms of the Wexpro settlement agreement (Note 8).
Regulation of Underground Storage: Clear Creek Storage Company,
LLC operates an underground gas storage facility that is
regulated by the Federal Energy Regulatory Commission (FERC).
The FERC establishes rates for the storage of natural gas, and
regulates 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.
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 our commercial bank accounts that result in available
funds the next business day.
Notes Receivable from Questar: Notes receivable from Questar
represent interest bearing demand notes for cash loaned to
Questar until needed in the Company's operations. The funds
are centrally managed by Questar and earn an interest rate that
is identical to the interest rate paid by the Company for
borrowings from Questar.
Property, Plant and Equipment: Property, plant and equipment
is stated at cost. The Company uses the full-cost accounting
method for a majority of its gas and oil exploration and
development activities. However, as ordered by the PSCU, the
successful efforts method of accounting is utilized with
respect to costs associated with certain "cost of service" oil
and gas properties managed and developed by Wexpro and
regulated for ratemaking purposes. Cost of service oil and gas
properties are those properties for which the operations and
return on investment are regulated by the Wexpro settlement
agreement (see Note 8). 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.
Full cost accounting
Under the full cost method, all costs associated with the
acquisition, exploration and development of oil and gas
reserves, including certain directly related internal employee
costs, are capitalized. Such amounts include the cost of
drilling and equipping productive wells, dry hole costs, lease
acquisition costs, delay rentals, and costs related to such
activities. The internal costs capitalized are directly
attributable to acquisition, exploration, and development
activities and do not include costs related to production,
general corporate overhead or similar activities. Exclusive of
field-level costs, the Company capitalized $3.6 million, $3.0
million and $2.6 million of internal costs in 2000, 1999 and
1998, respectively. Costs associated with production and
general corporate activities are expensed in the period
incurred. Sales of oil and gas properties, whether or not
being amortized currently, are accounted for as adjustments of
capitalized costs, with no gain or loss recognized, unless such
adjustments would significantly alter the relationship between
capitalized costs and proved reserves.
The Company limits, on a country-by-country cost-center basis,
the capitalized costs of oil and gas properties, net of
accumulated amortization and related deferred taxes, to the
full-cost ceiling. The full-cost ceiling comprises the present
value of estimated future net revenues from proved oil and gas
reserves plus the cost of unproved properties not being
amortized, all adjusted for the effect of related income taxes.
The present value calculation is based upon current economic
and operating conditions and estimated future development
expenditures, discounted at 10%. If capitalized costs exceed
the full-cost ceiling, the excess is expensed. In 1998, the
Company recorded a $31 million write-down of oil and gas
properties pursuant to the ceiling limitation required by the
full-cost accounting method.
Capitalized costs are amortized, on a country-by-country
cost-center basis, by an energy equivalent unit-of-production
method based upon production and estimates of proved gas and
oil reserves. The Company presently has two cost centers: the
United States and Canada. Amortizable costs include
developmental drilling in progress as well as estimates of
future development costs of proved reserves, but exclude the
costs of certain unproved gas and oil properties until the
properties are evaluated. The estimated costs of future site
restoration, dismantlement, and abandonment of producing
properties are expected to be offset by the estimated salvage
value of the lease and well equipment.
The aggregate costs of unproved properties not being amortized
are assessed at least annually for possible impairments or
reduction in value. Significant properties are assessed
individually. If a reduction in value has occurred, costs
being amortized are increased. Of the $76.2 million of net
unproved property costs at December 31, 2000, excluded from the
amortizable base, $22.9 million, $10.4 million, and $20.5
million were incurred in 2000, 1999 and 1998, respectively.
Based on anticipated future exploration and development
activities, the Company expects the majority of the costs of
unproved properties currently excluded to be evaluated and
included in the amortization calculation within the next five
years.
Successful efforts accounting
The Company uses the successful efforts method of accounting
for costs associated with the development of cost-of-service
oil and gas properties. The cost to drill and equip
development wells, successful or unsuccessful, and construct
related facilities are capitalized. Geological and geophysical
costs are expensed as incurred.
Capitalized costs are amortized on an individual field basis
using the unit-of-production method based upon proved developed
oil and gas reserves attributable to the field. Costs of
future site restoration, dismantlement, and abandonment for
producing properties are accrued as part of depreciation and
amortization expense for tangible equipment by assuming no
salvage value in the calculation of the unit of production
rate.
Gathering, processing and marketing
The investments in gathering facilities, processing plants and
other general support property, plant and equipment are
generally depreciated using the straight-line method based upon
estimated useful lives ranging from 3 to 20 years.
SFAS 121
The Company follows the provisions of Statement of Financial
Accounting Standards (SFAS) 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" in evaluating impairment of the Company's cost of service
oil and gas properties (accounted for under the successful
efforts method) and its gathering, processing and other
property, plant and equipment.
Depreciation and amortization
2000 1999 1998
(In Thousands)
Depreciation and amortization expense
Full-cost oil and
gas properties $64,619 $61,057 $55,015
Cost-of-service oil
and gas properties 13,922 12,665 11,379
Gathering, processing
and marketing 5,934 4,886 4,983
$84,475 $78,608 $71,377
Average depreciation and amortization rates per Mcf equivalent
for the 12 months ended December 31, were as follows:
Full-cost amortization rate
U.S. $ 0.78 $ 0.81 $ 0.83
Canada (in U.S. dollars) 0.85 0.65 1.04
Combined U.S. and Canada 0.79 0.80 0.85
Cost-of-service oil and gas
properties $ 0.44 $ 0.42 $ 0.39
Capitalized Interest and Allowance for Funds Used During
Construction: The Company capitalizes interest costs, when
applicable, related to gathering, processing, and marketing
activities during the construction period of plant and
equipment. Interest costs related to full cost oil and gas
activities are expensed in the period incurred. Gross debt
expense aggregated $22,922,000, $17,363,000, and $13,249,000,
in 2000, 1999 and 1998, respectively. Debt expense was reduced
by $618,000 of capitalized interest in 1998. Under provisions
of the Wexpro settlement agreement, the Company capitalizes an
allowance for funds used during construction (AFUDC) on
cost-of-service construction projects. The FERC requires the
capitalization of AFUDC during the construction period of plant
and equipment. AFUDC amounted to $2,163,000, $357,000, and
$745,000, in 2000, 1999, and 1998, respectively, and is
included in Interest and Other Income in the Consolidated
Statements of Income.
Foreign Currency Translation: The Company conducts gas and oil
exploration and production in western Canada. The local
currency is the functional currency of the Company's foreign
operations. Translation from the functional currency 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
for the period. Adjustments resulting from such translations
are reported as a separate component of other comprehensive
income in shareholder's equity. Deferred income taxes have
been provided on translation adjustments because the earnings
are not considered to be permanently invested.
Market Risks: The Company's primary market-risk exposures arise
from commodity price changes for natural gas and oil, changes
in long-term interest rates, and foreign currency exchange
rates.
Hedging Policy: The Company has established policies and
procedures for managing market risks through the use of
commodity-based derivative arrangements. A primary objective
of these hedging transactions is to protect the Company's
commodity sales from adverse changes in energy prices. 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 Company's revolving credit facility, not
more than 75% of Market Resources' production quantities can be
committed to hedging arrangements. The Company does not enter
into derivative arrangements for speculative purposes.
Energy Price Risk Management: Market Resources enters into
swaps, futures contracts or options agreements to hedge
exposure to price fluctuations in connection with marketing of
the Company's natural gas and oil production, and to secure a
known margin for the purchase and resale of gas, oil and
electricity in marketing activities. It is expected that there
is a high degree of correlation between the changes in market
value of such contracts and the market price ultimately
received on the hedged physical transactions. The timing of
production and of the hedge contracts is 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 which do not have high correlation with the related
physical transactions are marked-to-market and recognized in
the current period income.
Interest Rate Risk Management: The Company borrows funds under
variable interest rate arrangements. Variable-rate agreements
expose the Company to market risk related to changes in
interest rates.
Credit Risk: The Company's primary market areas are the Rocky
Mountain regions of the United States and Canada and the
Mid-continent 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 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, and believes
that losses from non-performance are unlikely to occur.
Income Taxes: The Company accounts for income tax expense on a
separate return basis. Pursuant to the Internal Revenue Code
and associated regulations, the Company's operations are
consolidated with those of Questar and its subsidiaries for
income tax reporting purposes. The Company records tax
benefits as they are generated. The Company receives payments
from Questar for such tax benefits as they are utilized on the
consolidated return.
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 Statements of Shareholder's Equity.
Other comprehensive income transactions that currently apply to
QMR result from changes in market value of securities available
for sale 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 market value.
Income or loss is realized when the securities available for
sale are sold. The balance in accumulated foreign currency
translation adjustments amounted to a negative $1,521,000 and a
negative $375,000, at December 31, 2000 and 1999, respectively.
The balance of an unrealized loss on securities available for
sale was $2,515,000 at December 31, 1999. Income is realized
when the securities available for sale are sold. Proceeds from
sales of available for sale securities were $18.4 million and
$1.2 million for the year ended December 31, 2000 and 1999,
respectively. Income tax expenses associated with realized
gains from selling securities available for sale were $1.5
million in 2000 and $.1 million in 1999. Beginning in 2001,
other comprehensive income will include mark-to-market
adjustments of the Company's qualified energy derivatives.
The balances of cumulative other comprehensive losses for the
12 months ended December 31, were as follows:
2000 1999
(In Thousands)
Unrealized loss on securities ($2,515)
Foreign currency translation
adjustment ($1,521) (375)
Cumulative other comprehensive
income ($1,521) ($2,890)
New Accounting Standard: The Company is required to adopt the
accounting provisions of SFAS 133, as amended, "Accounting for
Derivative Instruments and Hedging Activities" beginning in
January 2001. SFAS 133 addresses the accounting for derivative
instruments, including certain derivative instruments embedded
in other contracts. Under the standard, entities are 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, entities
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 on the hedged item attributable to the
risk being hedged. 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
amounts excluded from the assessment of hedge effectiveness, as
well as the ineffective portion of the gain or loss, is
reported in earnings immediately.
As of January 1, 2001, the Company structured a majority of its
energy derivative instruments as cash flow hedges. As a result
of adopting SFAS 133 in January 2001, the Company expects to
record a liability for derivative instruments of approximately
$121 million. The offset to this amount, net of income taxes,
will be recorded as a loss in other comprehensive income in the
shareholders' equity section of the balance sheet. The
fair-value calculation does not consider changes in fair value
of the corresponding scheduled equity physical transactions.
Acquisitions: On January 26, 2000, a subsidiary of QMR
acquired 100% of the outstanding shares of Canor Energy Ltd
from NI Canada ULC, a subsidiary of Northwest Natural Gas Co.
for cash of $61 million (US) plus the assumption of $5.4
million of short-term debt. The transaction was accounted for
as a purchase. Canor owns an interest in more than 800 wells
located in Alberta, British Columbia and Saskatchewan provinces
of Canada. Canor's proven gas and oil reserves at the time of
purchase were estimated at 61.1 billion cubic feet equivalent.
Reclassifications: Certain reclassifications were made to the
1999 and 1998 financial statements to conform with the 2000
presentation.
Note 2 - Debt
QMR has a $300 million revolving credit facility agented by
Bank of America. Borrowing under this agreement amounted to
$244.4 million and $264.9 million at December 31, 2000 and
1999, respectively. The average interest rate as of December
31, was 7.01% in 2000 and 6.54% in 1999. The loan is segmented
into United States and Canadian portions. The United States
portion of the loan is a 5-year facility with $230 million
available. The Canadian portion amounts to $70 million and is a
6-year facility. The interest rate is generally equal to LIBOR
plus a premium. QMR's revolving credit facility contains
covenants specifying a minimum amount of net equity and a
maximum ratio of debt to equity. Under the most restrictive
terms of the revolving credit facility, Market Resources could
pay a dividend of $84.2 million.
Maturities of long-term debt for the five years following
December 31, 2000, in thousands of dollars were as follows:
2001 $ -
2002 2,719
2003 12,719
2004 182,719
2005 2,719
Questar makes loans to QMR under a short-term borrowing
arrangement. Short-term notes payable to Questar outstanding
as of December 31, 2000 amounted to $51 million with an
interest rate of 6.91% and $24.5 million as of December 31,
1999 with an interest rate of 6.61%.
On March 6, 2001, Market Resources issued in a public offering
$150 million of 7.5% notes due 2011. Market Resources applied
the proceeds of the debt offering to repay a portion of its
outstanding floating-rate debt.
Cash paid for interest was $23,414,000 in 2000, $16,964,000 in
1999 and $13,229,000 in 1998.
Note 3 - Financial Instruments and Risk Management
The carrying amounts and estimated fair values of the Company's
financial instruments were as follows:
December 31, 2000 December 31, 1999
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
(In Thousands)
Financial assets
Cash and cash equivalents $3,980 $3,980
Notes receivable from
Questar $4,000 $4,000
Financial liabilities
Short-term loans 63,500 63,500 25,746 25,746
Long-term debt 244,377 244,377 264,894 264,894
Gas and oil price hedging
contracts - (98,000) - (6,200)
The Company used the following methods and assumptions in
estimating fair values: (1) Cash and cash equivalents, notes
receivable and short-term loans - the carrying amount
approximates fair value; (2) Long-term debt - the carrying
amount of variable-rate debt approximates fair value; (3) Gas
and oil price hedging contracts - the fair value of 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, 2000,
was $18.30 per barrel and was based on the average of fixed
amounts in contracts which settle against the NYMEX. All oil
contracts relate to Company-owned production where basis
adjustments would result in a net to the well price of $17.20
per barrel. The average price of the gas contracts at December
31, 2000 was $3.87 per MMBtu representing the average of
contracts with different terms including fixed, various "into
the pipe" postings and NYMEX references. Gas-hedging contracts
were in place for Market Resources-owned production and
gas-marketing transactions. Transportation and
heat-value adjustments on the hedges of Company-owned gas as of
December 31, 2000, would result in a price between $2.90 and
$3.15 per Mcf, net back to the well.
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 gas and oil price-hedging
activities, the fair value calculation does not consider the
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).
Energy-Price Risk Management
Market Resources held hedge contracts covering the price
exposure for about 50.5 million dth of gas and 1 million
barrels of oil at December 31, 2000. A year earlier the
contracts covered 72.1 million dth of natural gas and 2.4
million barrels of oil. The 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, 2000, had terms extending through December 2003,
with about 91% of those contracts expiring by the end of 2001.
A primary objective of energy-price hedging is to protect
product sales from adverse changes in energy prices. The
Company does not enter into hedging contracts for speculative
purposes.
Credit Risk.
The Company's primary market areas are the Rocky Mountain
regions of the United States and Canada and the Mid-continent
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, and believes
that losses from non-performance are unlikely to occur.
Interest-Rate Risk Management
The Company held floating-rate long-term debt at December 31,
2000 and 1999. The book value of variable-rate debt
approximates fair value.
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 $54.4 million
(U.S.) is expected to be repaid from future operations of the
foreign company.
Note 4 - Income Taxes
The components of income taxes for years ended December 31 were
as follows:
2000 1999 1998
(In Thousands)
Federal
Current $13,678 $11,411 $4,263
Deferred 22,330 4,826 (86)
State
Current 1,129 1,568 228
Deferred 2,015 620 1,007
Foreign 6,394 159 (6,431)
$45,546 $18,584 ($1,019)
The difference between income tax expense and the tax computed
by applying the statutory federal income tax rate of 35% to
income from continuing operations before income taxes is
explained as follows:
2000 1999 1998
(In Thousands)
Income from continuing operations
before income taxes $130,588 $64,450 $15,706
Federal income taxes at
statutory rate $45,706 $22,558 $5,497
State income taxes, net of federal
income tax benefit 2,043 1,422 803
Nonconventional fuel credits (4,655) (5,282) (5,736)
Foreign income taxes 2,474 48 (1,771)
Other (22) (162) 188
Income taxes $45,546 $18,584 ($1,019)
Effective income tax rate 34.9% 28.8% -
Significant components of the Company's deferred income taxes
at December 31 were as follows:
2000 1999
(In Thousands)
Deferred tax liabilities
Property, plant and equipment $106,472 $74,333
Other 624 509
Total deferred tax liabilities 107,096 74,842
Deferred tax assets
Alternative minimum tax and
nonconventional fuel credit
carryforwards 2,468
Reserves, compensation plans
and other 10,637 12,438
10,637 14,906
Net deferred income taxes $96,459 $59,936
The Company paid $25,586,000 in 2000 and $7,183,000 in 1999 for
income taxes. In 1998, Market Resources received $1,856,000 in
settlement of income taxes.
Note 5 - Litigation and Commitments
On January 4, 2001, a district court judge in Texas County,
Oklahoma, approved the settlement agreement reached by the
Questar defendants and Union Pacific Resources Company,
predecessor in interest to Questar Exploration & Production
(QE&P), as defendants in the case of Bridenstine v.
Kaiser-Francis Oil Company. Under the terms of the settlement,
the Company and Union Pacific Resources paid a total of $22.5
million ($16.5 million by the Company) to resolve all of the
issues in the litigation. The Questar defendants disputed
plaintiffs' claims, but settled the lawsuit to avoid the
uncertainty of a jury verdict. Payment of the settlement funds
did not have a material adverse effect on the Company's results
of operations, financial position, or liquidity.
There are various other legal proceedings against Market
Resources. 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.
Questar Energy Trading has contracted for firm-transportation
services with various pipelines to transport 76.2 Mdth per day
of gas. The contracts extends for six years and have an annual
cost of approximately $3 million. Due to market conditions and
competition, it is possible that Questar Energy Trading may be
unable to sell enough gas to fully utilize the contracted
capacity. Questar Energy Trading has reserved firm-storage
capacity of 1,065 Mdth per day with Questar Pipeline through
2008 with an annual cost of $627,000.
The minimum future payments under the terms of long-term
operating leases for the Company's primary office locations for
the four years following December 31, 2000, are as follows:
(In Thousands)
2001 $1,885
2002 1,445
2003 522
2004 44
Total minimum future rental payments have not been reduced for
sublease rental receipts of $187,000, and $24,000, which are
expected to be received in the years ended December 31, 2001,
and 2002, respectively. Total rental expense amounted to
$2,087,000 in 2000, $1,804,000 in 1999 and $1,397,000 in 1998.
Sublease rental receipts were $118,000 in 2000 and $94,000 in
1999.
Note 6 - Employment Benefits
Pension Plan: Substantially all of QMR's employees are covered
by Questar's defined benefit pension plan, although some
employees have elected other benefits in place of a pension
benefit. Benefits are generally based on 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
applicable laws and regulations. Plan assets consist
principally of equity securities and corporate and U.S.
government debt obligations. Pension cost was $385,000 in 2000,
$887,000 in 1999 and $761,000 in 1998.
Market Resources' portion of plan assets and benefit
obligations is not determinable because the plan assets are not
segregated or restricted to meet the Company's pension
obligations. If the Company were to withdraw from the pension
plan, the pension obligation for the Company's employees would
be retained by the pension plan. At December 31, 2000,
Questar's accumulated benefit obligation exceeded the fair
value of plan assets.
Postretirement Benefits Other Than Pensions: Market Resources
pays a portion of health-care costs and life insurance costs
for employees. The Company linked the health-care benefits to
years of service and limited the Company's monthly health care
contribution per individual to 170% of the 1992 contribution.
Employees hired after December 31, 1996, do not qualify for
postretirement medical benefits under this plan. 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 a transition obligation over a
20-year period beginning in 1992. Costs of postretirement
benefits other than pensions were $1,654,000 in 2000,
$1,158,000 in 1999 and $1,018,000 in 1998.
Market Resources' portion of plan assets and benefit
obligations related to postretirement medical and life
insurance benefits is not determinable because the plan assets
are not segregated or restricted to meet the Company's
obligations.
Postemployment Benefits: Market Resources 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 the present value both
of current and future costs. The Company's postemployment
benefit liability at December 31, 2000 and 1999 was $555,000
and $381,000, respectively based on a discount rate of 7.75%.
Employee Investment Plan: The Company participates in
Questar's Employee Investment Plan (EIP), which allows eligible
employees to purchase Questar common stock or other investments
through payroll deduction of pretax earnings. The Company pays
for contributions of Questar common stock to the EIP of
approximately 80% of the employees' purchases of the maximum of
6% of eligible earnings and contributes an additional $200 of
common stock in the name of each eligible employee. The
Company's expense and contribution to the plan was $1,125,000
in 2000, $895,000 in 1999 and $811,000 in 1998.
Note 7 - Related Party Transactions
QMR receives a significant portion of its revenues from
services provided to Questar Gas Company. The Company received
$92,455,000 in 2000, $79,324,000 in 1999 and $75,171,000 in
1998 for operating cost-of-service gas properties, gathering
gas and supplying a portion of gas for resale, among other
services provided to Questar Gas. Operation of cost-of-service
gas properties is described in Wexpro Settlement Agreement
(Note 8). The Company also received revenues from other
affiliated companies totaling $397,000 in 2000, $384,000 in
1999 and $310,000 in 1998.
Questar performs certain administrative functions for QMR. The
Company was charged for its allocated portion of these services
which totaled $6,626,000 in 2000, $4,469,000 in 1999 and
$3,970,000 in 1998. These costs are included in operating and
maintenance expenses and are allocated based on each
affiliate's proportional share of revenues, net of gas costs;
property, plant and equipment; and payroll. Management
believes that the allocation method is reasonable.
QMR's subsidiaries contracted for transportation and storage
services with Questar Pipeline and paid $2,146,000 in 2000,
$3,378,000 in 1999 and $3,968,000 in 1998 for those services.
Questar InfoComm Inc is an affiliated company that provides
some data processing and communication services to Market
Resources. The Company paid Questar InfoComm $1,904,000 in
2000, $2,276,000 in 1999 and $2,273,000 in 1998.
QMR has a 5-year lease with Questar for space in an office
building located in Salt Lake City, Utah and owned by a third
party. The third party has a lease arrangement with Questar
Corp, which in turn sublets office space to affiliated
companies. The annual lease payment, which began October of
1997, is $863,000.
The Company received interest income from affiliated companies
of $355,000 in 2000, $681,000 in 1999 and $1,908,000 in 1998.
Market Resources incurred debt expense to affiliated companies
of $2,520,000 in 2000, $3,350,000 in 1999 and $3,331,000 in
1998.
Note 8 - 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 13.64%. 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 18.64%. 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 21.64%.
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 13.64%.
Note 9 - Business Segment Information
QMR is a sub-holding company that has three primary business
segments: exploration and production, the management and
development of cost of service properties, and gathering,
processing and marketing. QMR's reportable segments are
strategic business units with similar operations and management
objectives. The reportable segments are managed separately
because each segment requires different operational assets,
technology and management strategies.
Year Ended December 31,
2000 1999 1998
(In Thousands)
Revenues from Unaffiliated Customers
Exploration and production $245,728 $162,475 $135,509
Cost of service 15,179 8,844 10,025
Gathering, processing and marketing 388,293 247,284 237,257
$649,200 $418,603 $382,791
Revenues from Affiliated Companies
Exploration and production $ 18 $ - $ -
Cost of service 73,721 62,335 58,581
Gathering, processing and marketing 19,114 17,373 16,900
$ 92,853 $ 79,708 $ 75,481
Depreciation and Amortization Expense
Exploration and production $ 64,619 $ 61,057 $ 55,015
Cost of service 13,922 12,665 11,379
Gathering, processing and marketing 5,934 4,886 4,983
$ 84,475 $ 78,608 $ 71,377
Operating Income (Loss)
Exploration and production $ 89,862 $ 37,406 $ (6,063)
Cost of service 38,502 32,948 28,218
Gathering, processing and marketing 11,739 6,424 3,474
$140,103 $ 76,778 $ 25,629
Interest and Other Income
Exploration and production $ 2,606 $ 2,209 $ 2,256
Cost of service 472 534 971
Gathering, processing and marketing 7,553 1,529 411
$ 10,631 $ 4,272 $ 3,638
Debt Expense
Exploration and production $ 17,976 $ 14,770 $ 11,552
Cost of service 721 582 149
Gathering, processing and marketing 4,225 2,011 930
$ 22,922 $ 17,363 $ 12,631
Income Taxes
Exploration and production $ 25,411 $ 4,037 $(12,102)
Cost of service 13,873 12,020 10,387
Gathering, processing and marketing 6,262 2,527 696
$ 45,546 $ 18,584 $ (1,019)
Income (Loss) From Continuing Operations
Exploration and production $ 49,371 $ 20,808 $ (3,257)
Cost of service 24,380 20,880 18,653
Gathering, processing and marketing 11,291 4,178 1,329
$ 85,042 $ 45,866 $ 16,725
Fixed Assets - Net
Exploration and production $ 569,784 $482,043 $496,884
Cost of service 155,374 137,584 129,573
Gathering, processing and marketing 79,096 71,354 69,055
$ 804,254 $690,981 $695,512
Capital Expenditures
Exploration and production $ 149,098 $ 81,863 $219,608
Cost of service 32,048 21,076 26,653
Gathering, processing and marketing 14,824 31,330 8,285
$ 195,970 $134,269 $254,546
GEOGRAPHIC INFORMATION
Revenues
United States $ 703,981 $485,995 $447,798
Canada 38,072 12,316 10,474
$ 742,053 $498,311 $458,272
Fixed Assets - Net
United States $ 698,959 $ 654,961 $662,260
Canada 105,295 36,020 33,252
$ 804,254 $ 690,981 $695,512
Note 10 - Supplemental Oil and Gas Information (Unaudited)
The Company uses the full-cost accounting method for the
majority of its oil and gas exploration and development
activities. However, 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 oil and gas properties managed and developed by
Wexpro and regulated for ratemaking purposes. Cost-of-service
oil and gas properties are those properties for which the
operations and return on investment are regulated by the Wexpro
settlement agreement (See Note 8).
Oil and Gas Exploration and Development Activities: The
following information is provided with respect to Questar's oil
and gas exploration and development activities, located in the
United States and Canada.
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas
exploration and development activities and the related amounts
of accumulated depreciation and amortization follow:
As of December 31, United Canada Total
States
(In Thousands)
2000
Proved properties $962,942 $119,067 $1,082,009
Unproved properties 48,429 27,787 76,216
Support equipment and
facilities 12,002 1,177 13,179
1,023,373 148,031 1,171,404
Accumulated depreciation
and amortization 558,884 42,736 601,620
$464,489 $105,295 $569,784
1999
Proved properties $885,333 $58,016 $943,349
Unproved properties 58,248 11,529 69,777
Support equipment and
facilities 12,418 990 13,408
955,999 70,535 1,026,534
Accumulated depreciation
and amortization 509,976 34,515 544,491
$446,023 $36,020 $482,043
1998
Proved properties $869,514 $48,723 $918,237
Unproved properties 49,724 12,763 62,487
Support equipment and
facilities 13,949 929 14,878
933,187 62,415 995,602
Accumulated depreciation
and amortization 469,555 29,163 498,718
$463,632 $33,252 $496,884
Unproved Properties Excluded from Full-Cost Amortization
Unproved properties are excluded from full-cost amortization
until evaluated. A summary of costs excluded from amortization
at December 31, 2000, and the period in which these costs were
incurred are listed below by cost center:
Year Costs Incurred
1997 and
Total 2000 1999 1998 Prior
(In Thousands)
United States
Acquisition $35,387 $2,932 $7,266 $17,689 $7,500
Exploration 13,042 2,340 2,967 1,868 5,867
48,429 5,272 10,233 19,557 13,367
Canada
Acquisition 23,786 14,903 71 534 8,278
Exploration 4,002 2,703 125 382 792
27,788 17,606 196 916 9,070
Total U. S.
and Canada $76,217 $22,878 $10,429 $20,473 $22,437
Costs Incurred
The following costs were incurred in oil and gas exploration
and development activities:
Year Ended December 31, United Canada Total
States
(In Thousands)
2000
Property acquisition
Unproved $3,082 $14,885 $17,967
Proved 1,202 31,900 33,102
Exploration 5,412 3,078 8,490
Development 65,709 30,470 96,179
$75,405 $80,333 $155,738
1999
Property acquisition
Unproved $12,547 $351 $12,898
Proved 3,746 18 3,764
Exploration 7,467 501 7,968
Development 53,488 3,745 57,233
$77,248 $4,615 $81,863
1998
Property acquisition
Unproved $29,367 $145 $29,512
Proved 126,723 3,144 129,867
Exploration 10,055 1,222 11,277
Development 43,090 5,363 48,453
$209,235 $9,874 $219,109
Results of Operations
Following are the results of operations of Market Resources'
oil and gas exploration and development activities, before
corporate overhead and interest expenses. The Company recorded
write-downs of its full-cost oil and gas properties in
accordance with the limitation of its full-cost ceiling in
1998.
United
States Canada Total
Year Ended December 31, 2000 (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 49,116 9,370 58,486
Depreciation and amortization 54,942 9,677 64,619
Total expenses 104,058 19,047 123,105
Revenues less expenses 103,616 19,025 122,641
Income taxes - Note A 33,890 10,939 44,829
Results of operations before
corporate overhead and interest
expenses $69,726 $8,086 $77,812
Year Ended December 31, 1999
Revenues $150,159 $12,316 $162,475
Production expenses 41,948 3,681 45,629
Depreciation and amortization 57,545 3,512 61,057
Total expenses 99,493 7,193 106,686
Revenues less expenses 50,666 5,123 55,789
Income taxes - Note A 13,616 2,567 16,183
Results of operations before
corporate overhead and interest
expenses $37,050 $2,556 $39,606
Year Ended December 31, 1998
Revenues $125,035 $10,474 $135,509
Production expenses 38,788 3,004 41,792
Depreciation and amortization 49,740 5,275 55,015
Write-down of oil and gas properties 19,000 12,000 31,000
Total expenses 107,528 20,279 127,807
Revenues less expense 17,507 (9,805) 7,702
Income taxes - Note A 1,191 (4,030) (2,839)
Results of operations before
corporate overhead and interest
expenses $16,316 ($5,775) $10,541
Note A - Income tax expenses has been reduced by
nonconventional fuel tax credits of $4,655,000 in 2000,
$5,282,000 in 1999 and $5,736,000 in 1998.
Estimated Quantities of Proved Oil and Gas 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 oil and gas 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.
United Nat. Gas United Oil
States Canada Total States Canada Total
(MMcf) (MBbl)
Proved Reserves
Balance at January
1, 1998 357,529 21,134 378,663 12,664 2,435 15,099
Revisions of
estimates 378 (3,568) (3,190) (3,165) 238 (2,927)
Extensions and
discoveries 28,598 1,984 30,582 442 261 703
Purchase of reserves
in place 129,207 5,110 134,317 3,720 71 3,791
Sale of reserves
in place (440) (440) (76) (76)
Production (48,584) (2,725) (51,309) (1,936) (404) (2,340)
Balance at December
31, 1998 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
Proved-Developed Reserves
Balance at January
1, 1998 300,550 16,670 317,220 10,769 1,851 12,620
Balance at December
31, 1998 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
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.
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.
Year Ended December 31, United
States Canada Total
(In Thousands)
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 (1,493,301) (225,234) (1,718,535)
Future net cash flows 2,856,462 267,054 3,123,516
10% annual discount to reflect
timing of net cash flows (1,314,258) (117,637) (1,431,895)
Standardized measure of discounted
future net cash flows $1,542,204 $149,417 $1,691,621
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 (183,767) (11,656) (195,423)
Future net cash flows 689,369 65,908 755,277
10% annual discount to reflect
timing of net cash flows (283,055) (23,193) (306,248)
Standardized measure of discounted
future net cash flows $406,314 $42,715 $449,029
1998
Future cash inflows $982,404 $66,885 $1,049,289
Future production costs (320,355) (22,088) (342,443)
Future development costs (45,138) (696) (45,834)
Future income tax expenses (74,738) (74,738)
Future net cash flows 542,173 44,101 586,274
10% annual discount to reflect
timing of net cash flows (216,907) (14,809) (231,716)
Standardized measure of discounted
future net cash flows $325,26 $29,292 $354,558
The principal sources of change in the standardized measure of
discounted future net cash flows were:
Year Ended December 31,
2000 1999 1998
(In Thousands)
Beginning balance $449,029 $354,558 $301,162
Sales of oil and gas
produced, net of production
costs (187,260) (116,846) (93,717)
Net changes in prices and
production costs 1,636,707 170,012 (53,626)
Extensions and discoveries,
less related costs 492,398 79,511 24,120
Revisions of quantity estimates 70,155 28,665 (14,399)
Purchase of reserves in place 33,102 3,764 129,867
Sale of reserves in place (1,867) (33,043) (540)
Accretion of discount 44,903 35,456 30,116
Net change in income taxes (804,799) (66,293) 11,550
Change in production rate (50,077) (8,859) 6,728
Other 9,330 2,104 13,297
Net change 1,242,592 94,471 53,396
Ending balance $1,691,621 $449,029 $354,558
Cost-of-Service Activities
The following information is provided with respect to
cost-of-service oil and gas 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 oil and gas properties
net of the related accumulated depreciation and amortization
were as follows:
December 31,
2000 1999 1998
(In Thousands)
Proved properties $348,403 $318,451 $297,809
Accumulated depreciation
and amortization 193,029 180,867 168,236
$155,374 $137,584 $129,573
Costs Incurred
Costs incurred by Wexpro for cost-of-service oil and gas
producing activities were $32,066,000 in 2000, $21,273,000 in
1999 and $26,956,000 in 1998.
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.
Year Ended December 31,
2000 1999 1998
(In Thousands)
Revenues
From unaffiliated companies $15,179 $8,844 $10,025
From affiliates - Note A 73,721 62,335 58,581
Total revenues 88,900 71,179 68,606
Production expenses 27,861 18,548 22,439
Depreciation and amortization 13,922 12,665 11,379
Total expenses 41,783 31,213 33,818
Revenues less expenses 47,117 39,966 34,788
Income taxes 16,923 14,602 12,441
Results of operations
before corporate overhead
and interest expenses $30,194 $25,364 $22,347
Note A - Represents revenues received from Questar Gas pursuant
to Wexpro Settlement Agreement.
Estimated Quantities of Proved Oil and Gas Reserves
The following estimates were made by the Company's reservoir
engineers. No estimates are available for cost-of-service
proved-undeveloped reserves that may exist.
Natural Gas Oil
(MMcf) (MBbl)
Proved Developed Reserves
Balance at January 1, 1998 337,179 3,049
Revisions of estimates 15,017 (46)
Extensions and discoveries 25,077 333
Production (37,138) (613)
Balance at December 31, 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
GLOSSARY OF COMMONLY USED OIL AND GAS TERMS
"Bbl" means barrel. One barrel is the equivalent of 42 standard
U.S. gallons.
"Bcf" means billion cubic feet, a common unit of measurement of
natural gas.
"Bcfe" means billion cubic feet of natural gas equivalents. Oil
volumes are converted to natural gas equivalents using the ratio of
one barrel of crude oil to six thousand cubic feet of natural gas.
"Btu" means British thermal unit, measured as the amount of energy
required to raise the temperature of one pound of water one degree
Fahrenheit.
"Completion" means the completion of the processes necessary before
production of oil or natural gas occurs (e.g., perforating the
casing; installing permanent equipment in the well; or in the case
of a dry hole, the reporting of abandonment to the appropriate agency.
"Development well" means a well drilled into a known producing
formation in a previously discovered field.
"Dry hole" means a well found to be incapable of producing
hydrocarbons in sufficient quantities such that proceeds from the
sale of such production exceed production expenses and taxes.
"Dth" means decatherms or ten therms. One decatherm equals one
million Btu.
"Exploratory well" means a well drilled into a previously untested
geologic structure to determine the presence of oil or gas.
"Gross" natural gas and oil wells or "gross" acres equals the number
of wells or acres in which we have an interest.
"MBbls" means thousand barrels.
"Mcf" means thousand cubic feet.
"Mcfe" means thousand cubic feet of natural gas equivalents.
"MDths" means thousand decatherms.
"MMBbls" means million barrels.
"MMBtu" means million British thermal units.
"MMcf" means million cubic feet.
"MMDth" means million decatherms.
"Net" gas and oil wells or "net" acres are determined by multiplying
gross wells or acres by our working interest in those wells or acres.
"NGL" means natural gas liquids.
"Proved reserves" means those quantities of natural gas and crude
oil, condensate, and natural gas liquids on a net revenue interest
basis, which geological and engineering data demonstrate with
reasonable certainty to be recoverable under existing economic and
operating conditions. "Proved developed reserves" include proved
developed producing reserves and proved developed behind-pipe
reserves. "Proved developed producing reserves" include only those
reserves expected to be recovered from existing completion intervals
in existing wells. "Proved undeveloped reserves" include those
reserves expected to be recovered from new wells on proved undrilled
acreage or from existing wells where a relatively major expenditure
is required for recompletion.
"Reservoir" means a porous and permeable underground formation
containing a natural accumulation of producible natural gas and/or
oil that is confined by impermeable rock or water barriers and is
separate from other reservoirs.
"Working interest" means an interest that gives the owner the right
to drill, produce, and conduct operating activities on a property
and receive a share of any production.
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 29th day of March, 2001.
QUESTAR MARKET RESOURCES, INC.
(Registrant)
By /s/ G. L. Nordloh
G. L. Nordloh
President & 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/ G. L. Nordloh President & Chief Executive Officer;
G. L. Nordloh Director (Principal Executive Officer)
/s/ S. E. Parks Vice President, Treasurer and Chief
S. E. Parks Financial Officer (Principal
Financial Officer)
/s/B. Kurtis Watts Manager, Accounting
B. Kurtis Watts (Principal Accounting Officer)
*R. D. Cash Chairman of the Board; Director
*Teresa Beck Director
*Patrick J. Early Director
*William N. Jones Director
*G. L. Nordloh Director
*Keith O. Rattie Director
March 29, 2001 *By /s/ G. L. Nordloh
Date G. L. Nordloh, Attorney in Fact
EXHIBIT INDEX
Exhibit
Number Description
3.1.* Articles of Incorporation dated April 27, 1988 for Utah
Entrada Industries, Inc. (Exhibit No. 3.1. to the
Company's Form 10 dated April 12, 2000.)
3.2.* Articles of Merger, dated May 20, 1988, of
Entrada Industries, Inc., a Delaware
corporation and Utah Entrada Industries, Inc,
a Utah corporation. (Exhibit No. 3.2. to the
Company's Form 10 dated April 12, 2000.)
3.3.* Articles of Amendment dated August 31, 1998,
changing the name of Entrada Industries, Inc.
to Questar Market Resources, Inc. (Exhibit
No. 3.3. to the Company's Form 10 dated April
12, 2000.)
3.4.* Bylaws (as amended effective February 8,
2000.) (Exhibit No. 3.4. to the Company's
Form 10 dated April 12, 2000.)
4.1.* Indenture dated as of March 1, 2001, between the Questar
Market Resources, Inc. and Bank One, NA, as Trustee for
the Company's 71/2% Notes due 2011. (Exhibit No. 4.01. to
the Company's Current Report on Form 8-K dated March 6,
2001.)
4.2.* Form of 71/2% Notes due 2011. (Exhibit No. 4.02. to the
Company's Current Report on Form 8-K dated March 6, 2001.)
4.3. U.S. Credit Agreement, dated April 19, 1999,
by and among Questar Market Resources, Inc.,
as U.S. borrower, NationsBank, N.A., as U.S.
agent, and certain financial institutions, as
lenders, with the First Amendment dated May
17, 1999, the Second Amendment dated July 30,
1999, the Third Amendment dated November 30,
1999, the Fourth Amendment dated April 17,
2000, the Fifth Amendment dated October 6,
2000, and the Sixth Amendment dated February
9, 2001. (Exhibit No. 4.1. to the Company's
Form 10 dated April 12, 2000, for the U. S.
Credit Agreement, and the First, Second and
Third Amendments; Exhibit No. 4.1. to the
Company's Form 10/A dated November 9, 2000,
for the Fourth and Fifth Amendments.) The
Sixth Amendment is filed with this Report.1
4.4. Long-term debt instruments with principal amounts not
exceeding 10 percent of QMR's total consolidated assets
are not filed as exhibits. The Company will furnish a
copy of these agreements to the Commission upon request.
10.1.* Stipulation and Agreement, dated October 14, 1981,
executed by Mountain Fuel Supply Company [Questar Gas
Company]; Wexpro Company; 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 Questar Gas Company's Form 10-K Annual Report for 1981.)
21. Subsidiary Information.
24. Power of Attorney
________________________
*Exhibits so marked have been filed with the Securities and
Exchange Commission as part of the indicated filing and are
incorporated herein by reference.
1Exhibit so marked is management contract or compensation plan
or arrangement.