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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
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FORM 10/A
(AMENDMENT NO. 1 TO FORM 10)
GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR 12(g) OF
THE SECURITIES EXCHANGE ACT OF 1934
QUESTAR MARKET RESOURCES, INC.
(Exact name of registrant as specified in its charter)
UTAH
(State or other jurisdiction of
incorporation or organization)
180 East 100 South
P.O. Box 45601
Salt Lake City, Utah 84145-0601 (Zip Code)
(Address of principal executive offices)
87-0287750
(I.R.S. Employer Identification No.)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (801) 324-5202
SECURITIES TO BE REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS TO BE SO REGISTERED
NONE
NAME OF EACH EXCHANGE ON WHICH EACH CLASS IS TO BE REGISTERED
NONE
SECURITIES TO BE REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
COMMON STOCK, $1.00 PAR VALUE
(Title of class)
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS I1(a)
AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE
REDUCED DISCLOSURE FORMAT.
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TABLE OF CONTENTS
Page
Item 1. Business.................................................4
Item 2. Financial Information...................................12
Item 3. Properties..............................................19
Item 4. Security Ownership of Certain Beneficial Owners
and Management.......................................27
Item 5. Directors and Executive Officers........................27
Item 6. Executive Compensation..................................28
Item 7. Certain Relationships and Related Transactions..........28
Item 8. Legal Proceedings.......................................28
Item 9. Market Price of and Dividends on the Registrant's
Common Equity and Related Stockholder Matters........30
Item 10. Recent Sales of Unregistered Securities.................30
Item 11. Description of Registrant's Securities to be Registered.30
Item 12. Indemnification of Officers and Directors...............30
Item 13. Financial Statements and Supplementary Data.............31
Item 14. Changes in and Disagreements with Accountants and
Financial Disclosure.................................60
Item 15. Financial Statements and Exhibits.......................60
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 million 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 installation of permanent equipment for the
production of oil or natural gas, 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.
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"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.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 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 Form, 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, 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, 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.
The Company does not undertake an obligation to update forward-looking
information contained herein or elsewhere to reflect actual results,
changes in assumptions or changes in other factors affecting such
forward-looking information.
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ITEM 1. BUSINESS
General
Questar Market Resources Inc. (the "Company" or "QMR", which reference
shall include the Company's wholly-owned subsidiaries) is a
wholly-owned subsidiary of Questar Corporation. Questar Corporation
("Questar") is a publicly traded (NYSE: STR) diversified natural gas
company with two principal business units - Market Resources and
Regulated Services.
QMR and its subsidiaries comprise the Market Resources unit of Questar
and as such engage in oil and gas exploration, development and
production; gas gathering and processing; wholesale gas, electricity,
and hydrocarbon liquids trading; and the acquisition of producing oil
and gas properties. As noted in the following Questar organization
chart, QMR is a subholding company of Questar that conducts its
activities through Questar Exploration and Production Company
("Questar E&P") and its Canadian subsidiaries Celsius Energy Resources
Ltd. ("Celsius Ltd.") 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)
Questar Gas Management Company (Gathering and Processing)
Questar Regulated Services Company (Subholding Company)
Questar Gas Company (Retail Distribution)
Questar Pipeline Company (Transportation and Storage)
Management of Questar has identified QMR as the primary growth area
within Questar's business strategy. Questar expects to spend 70% 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 nonregulated
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.
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Business Strategy
QMR believes it can best meet and balance the expectations of its
parent and fixed income investors by pursuing 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
* employ technology and proven innovations to reduce costs
Oil and Gas Exploration and Production - Questar E&P, Celsius Ltd.,
and Canor
Together, QMR's exploration and production ("E&P") subsidiaries form a
unique E&P group that conducts a blended program of low-cost
development drilling, low-risk reserve acquisition, and high-quality
exploration. A low-risk oil and gas reserve acquisition is considered
by QMR to be one where (i) existing proved developed producing
reserves make up a substantial percentage (75%+) of the overall value
of the transaction with the remaining value supported by proved
undeveloped reserves recognized by the seller or developed by QMR;
(ii) cash flow from the properties, and/or borrowing capacity
associated with the properties, is sufficient to support development
of the acquisition properties; and (iii) the geographic location of
the properties and the technology required to develop the underlying
reserves are within our known areas of expertise. The E&P group also
maintains a geographical balance and diversity, while concentrating
its activities in core areas in which it has accumulated geologic
knowledge and developed significant management expertise. Core areas
of activity include the Rocky Mountain Region of Wyoming and Colorado;
the Mid-Continent Region of Oklahoma, the Texas Panhandle, East Texas,
and the Upper Gulf Coast; the Southwest Region of northwest New Mexico
and southwest Colorado; and the Western Canada Sedimentary Basin
located primarily in the Canadian province of Alberta.
At December 31, 1999, the Company had proved reserves of 597.6 Bcfe
of natural gas, crude oil and natural gas liquids associated with its
oil and gas exploration and development activities. On an energy
equivalent basis ratio of six Mcf of natural gas to one Bbl of crude
oil or natural gas liquids, natural gas comprised 86% of total proved
reserves. Proved developed reserves comprised 84% of the total proved
reserves on an energy equivalent basis.
A detailed description of the Company's proved reserves and their
geographic diversity can be found under "Item 3. Properties." These
proved reserve volumes do not include the cost of service reserves
managed and developed by Wexpro for Questar Gas Company, an affiliate
of the Company ("Questar Gas"). See "Development and Production -
Wexpro" below.
Development and Production - Wexpro
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' 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 10
of the Notes to Consolidated Financial Statements under Item 13 of
this Form 10. Ownership of Wexpro was moved from Questar Gas to QMR
in 1982.
Wexpro manages and develops cost of service properties for which the
operations and return on investment are regulated by the Wexpro
settlement agreement. Cost of service reserves are derived from
properties that primarily produce oil ("productive oil reservoirs") as
well as properties that primarily produce gas ("productive gas
reservoirs"). Pursuant
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to the terms of the settlement agreement, all hydrocarbon reserves
(oil, natural gas liquids and natural gas) in productive oil
reservoirs are owned by Wexpro. All hydrocarbon reserves associated
with productive gas reservoirs are owned by Questar Gas. Wexpro
manages and develops all cost of service reserves, in accordance with
the provisions of the settlement agreement, regardless of reserve
ownership.
Wexpro, unlike QMR's other E&P companies, generally 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 under the settlement agreement, Wexpro
charges Questar Gas for its cost plus a specified rate of return
(18.9% after tax at the end of 1999 and adjusted annually based on a
specified formula) on its net investment in such properties adjusted
for working capital and deferred taxes. 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 ("PSCW"), and
experts retained by those agencies.
The gas volumes produced by Wexpro for Questar Gas are reflected in
the latter's rates at cost of service. Cost of service gas produced
by Wexpro satisfied approximately 49% of Questar Gas' system
requirements during 1999. Questar Gas relies upon Wexpro's drilling
program to develop the properties from which the cost of service gas
is produced. During 1999, the average wellhead cost of cost of
service gas was $1.50 per Dth, which is lower than Questar Gas'
average price for field-purchased gas. To fulfill its obligations to
Questar Gas under the settlement agreement, Wexpro must continue to be
a prudent operator.
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 1999, produced 38.9 Bcf of
natural gas from cost of service properties and added cost of service
reserves of 52.4 Bcf through drilling activities and reserve estimate
revisions.
Wexpro has an ownership interest in the wells and appurtenant
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.
Gathering, Processing and Marketing - Questar Gas Management and
Questar Energy Trading
Questar Gas Management conducts gathering and processing activities in
the Rocky Mountain and Mid-Continent areas. Its activities are not
subject to regulation by the Federal Energy Regulatory Commission
("FERC"), because it is not engaged in transporting gas or selling gas
for resale in interstate commerce. 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 was formed in 1993, as a wholly-owned
subsidiary of Questar Pipeline Company, an affiliate of the Company
("Questar Pipeline"), to construct and operate the Blacks Fork
Processing Plant in southwestern Wyoming. It expanded in 1996 when
Questar Pipeline transferred its gathering assets and activities to
Questar Gas Management. In mid-1996, ownership of Questar Gas
Management was moved from Questar Pipeline to QMR and Questar Gas
Management acquired the processing plants that formerly belonged to
Questar E&P.
Questar Gas Management's gathering system, which consists of 1,400
miles of gathering lines, compressor stations, field dehydration
plants, and measuring stations, was largely built to gather production
from Questar Gas' cost of service properties. Under the terms of a
contract that was assigned with the gathering assets from Questar
Pipeline, Questar Gas Management is obligated to gather Questar Gas'
cost of service production for the life of the properties. During
1999, Questar Gas Management gathered 32.1 MMDth of natural gas for
Questar Gas, compared to 29.9 MMDth in 1998, for which it received
$4.7 million and $5.0 million in demand charges in 1999 and 1998,
respectively, from Questar Gas. Questar Gas Management's total gas
gathering volumes were 136.7 MMDth in 1999 compared to 120.5 MMDth in
1998.
Questar Gas Management's gathering system was originally built as part
of a regulated company. Questar Gas Management now must operate in a
different competitive environment. Often, new wells will have
connections with more than one gathering system, and producers insist
that gathering systems be tied to more than one pipeline.
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In addition to gathering activities, Questar Gas Management is also
engaged in processing activities. It owns a 50% interest in the
Blacks Fork Processing Plant, which has a daily capacity of 84 MMcf
and may be expanded during 2000. This plant, which is located in
southwestern Wyoming, strips liquids (e.g., ethane, butane) from
natural gas volumes. Questar Gas Management and Wexpro jointly own a
new processing facility located in the Canyon Creek area of
southwestern Wyoming that has an operating capacity of 45 MMcf per
day. Questar Gas Management also owns interests in other processing
plants in the Rocky Mountain and Mid-Continent areas.
Questar Energy Trading conducts energy marketing activities. It
combines gas volumes purchased from third parties and equity
production (production that is produced by other QMR subsidiaries) to
build a flexible and reliable portfolio. Questar Energy Trading
aggregates supplies of natural gas for delivery to large customers,
including industrial users, and other marketing entities. During
1999, Questar Energy Trading marketed a total of 101.1 MMDth of
natural gas, 2.0 MMBbls of liquids, and 10,000 megawatt-hours of
electricity and earned a gross profit margin of $4.1 million.
Questar Energy Trading uses derivatives as a risk management tool to
provide price protection for physical transactions involving equity
production and marketing transactions. Questar Energy Trading
executes hedges for equity production on behalf of Questar E&P and
does so with a variety of contracts for different periods of time.
See "Item 2. Financial Information - Market Risk."
As a wholesale marketing entity, Questar Energy Trading concentrates
on markets in the Pacific Northwest, Rocky Mountains, Midwest,
Southwest, California, and western Canada that are close to reserves
owned by affiliates or accessible by major pipelines.
To sustain its activities in an increasingly competitive environment
in which sellers and purchasers are becoming more sophisticated,
Questar Energy Trading needs to expand its capabilities. Through a
new limited liability company, it has filed an application with the
FERC and obtained authorization to construct and operate a private
storage reservoir in southwestern Wyoming adjacent to several
interstate pipelines and is negotiating partnerships with electricity
providers and others to obtain additional capability, expertise, and
access to sophisticated information technology.
Relationship with Questar
QMR and Questar are parties to several agreements which govern
different aspects of the QMR - Questar relationship. The more
significant of these agreements are described below. Also see Note 9
of the Notes to Consolidated Financial Statements under Item 13 of
this Form 10.
Tax Sharing Arrangement with Questar -- QMR accounts for income tax
expense on a separate return basis. Pursuant to Internal Revenue Code
regulations, the Company's operations are consolidated with those of
Questar and its subsidiaries for income tax purposes. The income tax
arrangement between QMR and Questar provides that the tax liability of
the group shall be allocated to the several members of the group on
the basis of the percentage of the total tax which the tax of such
member if computed on a separate return would bear to the total amount
of the taxes for all members of the group so computed. The Company
also receives payment for tax benefits used in the consolidated tax
return even if such benefits would not have been useable had the
Company filed a separate return.
Wexpro Settlement Agreement with Questar Gas -- Wexpro and Questar Gas
are parties to the Wexpro Settlement Agreement. Wexpro's operations
are subject to the terms of this agreement. The agreement became
effective August 1, 1981, and sets forth the rights of Questar Gas'
utility operations to share in the results of Wexpro's operations.
The agreement was approved by the Public Service Commission of Utah
("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 (productive oil reservoirs) previously transferred
from Questar Gas' 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
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approximately 13.7%. 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
reservoirs 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
18.7%. 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 (productive gas reservoirs) 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 21.7%.
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 13.7%.
Transportation Agreements with Affiliates -- As an affiliate of QMR,
Questar Pipeline transports natural gas produced from properties
operated by Wexpro. Questar Pipeline also transports volumes of
natural gas marketed by Questar Energy Trading, another QMR
subsidiary.
Transfer of Gas Gathering Assets -- In 1996, Questar Pipeline
transferred approximately $55 million of gas-gathering assets to its
subsidiary Questar Gas Management. Questar Gas Management was
subsequently transferred to QMR on July 1, 1996. The transaction was
in the form of a stock dividend payable to Questar, which stock
Questar then contributed to QMR.
Government Regulation
QMR's operations are subject to various levels of government controls
and regulation in the United States and Canada.
United States Regulation. In the United States, legislation
affecting the oil and gas industry has been pervasive and is
subject to continuing review for amendment or expansion. Pursuant
to such legislation, numerous federal, state and local
departments and agencies have issued extensive rules and
regulations binding on the oil and gas industry and its
individual members, some of which carry substantial penalties for
the failure to comply. Such laws and regulations have a
significant impact on oil and gas drilling and production
activities, increase the cost of doing business and,
consequently, affect profitability. Inasmuch as new legislation
affecting the oil and gas industry is commonplace and existing
laws and regulations are frequently amended or reinterpreted, QMR
is unable to predict the future cost or impact of complying with
such laws and regulations.
Exploration and Production. QMR's United States operations are
subject to various types of regulation at the federal, state 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 notification relating to the
presence, use and release of certain contaminants incidental to
oil and gas operations; and regulating the location of wells, the
method of drilling and casing wells, the use, transportation,
storage and disposal of fluids and materials used in connection
with drilling and production activities, surface usage and the
restoration
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of properties upon which wells have been drilled, the plugging
and abandoning of wells and the transporting 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 units, the number of wells which may be
drilled in a unit, and the unitization or pooling of oil and gas
properties. In this regard, some states allow the forced pooling
or integration of tracts to facilitate exploration while other
states rely on voluntary pooling of lands and leases, which may
make it more difficult to develop oil and gas properties. In
addition, state conservation laws establish maximum rates of
production from oil and gas wells, generally prohibit the venting
or flaring of gas, and impose certain requirements regarding the
ratable purchase of production. The effect of these regulations
is to limit the amounts of oil and gas QMR can produce from its
wells and to limit the number of wells or the locations at which
QMR can drill.
Certain of QMR's oil and gas leases, including most of its leases
in the San Juan Basin and many of the Company's leases in
southeast New Mexico and Wyoming, are granted by the federal
government and administered by various federal agencies. Such
leases require compliance with detailed federal regulations and
orders which regulate, among other matters, drilling and
operations on lands covered by these leases, and calculation and
disbursement of royalty payments to the federal government.
Environmental and Occupational Regulations. Various federal,
state and local laws and regulations concerning the discharge of
contaminants into the environment, the generation, storage,
transportation and disposal of contaminants or otherwise relating
to the protection of public health, natural resources, wildlife
and the environment may affect the Company's operations and
costs. In particular, the Company's oil and gas exploration,
development and production operations, its activities in
connection with storage and transportation of liquid
hydrocarbons, and its use of facilities for treating, processing,
recovering or otherwise handling hydrocarbons and wastes
therefrom are subject to environmental regulation by governmental
authorities. Such regulation has increased the cost of planning,
designing, drilling, installing, operating and abandoning the
Company's oil and gas wells and other facilities. Additionally,
these laws and regulations may impose substantial liabilities for
the Company's failure to comply with them or for any
contamination resulting from the Company's operations.
QMR takes the issue of environmental stewardship very seriously
and works diligently to comply with applicable environmental
rules and regulations. Compliance with such laws and regulations
has not had a material effect on the Company's operations or
financial condition in the past. However, because environmental
laws and regulations are becoming increasingly more stringent,
there can be no assurances that such laws and regulations or any
environmental law or regulation enacted in the future will not
have a material effect on the Company's operations or financial
condition. QMR is not aware of any currently pending
environmental legislation or regulation in the United States that
would have a material adverse effect on the Company if enacted.
QMR is also subject to laws and regulations concerning
occupational safety and health. Due to the continued changes in
these laws and regulations, and their judicial construction, QMR
is unable to predict with any reasonable degree of certainty its
future costs of complying with these laws and regulations.
Canadian Regulation. The oil and gas industry in Canada is
subject to extensive controls and regulations imposed by various
levels of government. It is not expected that any of these
controls or regulation will materially affect QMR's Canadian
operations, nor is it expected that the application of these
controls and regulations would be any more burdensome to QMR than
to other companies involved in oil and gas exploration and
production activities in Canada. The following are the most
important areas of control and regulation.
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The North American Free Trade Agreement. The North American Free
Trade Agreement ("NAFTA") which became effective on January 1,
1994, carries forward most of the material energy terms contained
in the Canada-U.S. Free Trade Agreement. In the context of energy
resources, Canada continues to remain free to determine whether
exports to the U.S. or Mexico will be allowed, provided that any
export restrictions do not: (i) reduce the proportion of energy
exported relative to the supply of the energy resource; (ii)
impose an export price higher than the domestic price; or (iii)
disrupt normal channels of supply. All parties to NAFTA are also
prohibited from imposing minimum export or import price
requirements.
Royalties and Incentives. Each province and the federal
government of Canada have legislation and regulations governing
land tenure, royalties, production rates and taxes, environmental
protection and other matters under their respective
jurisdictions. The royalty regime is a significant factor in the
profitability of oil and natural gas production. Royalties
payable on production from lands other than Crown lands are
determined by negotiations between the parties. Crown royalties
are determined by government regulation and are generally
calculated as a percentage of the value of the gross production
with the royalty rate dependent in part upon prescribed reference
prices, well productivity, geographical location, field discovery
date and the type and quality of the petroleum product produced.
From time to time, the governments of Canada, Alberta and British
Columbia have also established incentive programs such as royalty
rate reductions, royalty holidays and tax credits for the purpose
of encouraging oil and natural gas exploration or enhanced
recovery projects. These incentives generally have the effect of
increasing the cash flow to the producer.
Pricing and Marketing. The price received by the Company for its
oil and natural gas is generally determined by market factors,
most of which are beyond the Company's control. An order from
the National Energy Board ("NEB") is required for oil exports
from Canada. Any oil export to be made pursuant to an export
contract of longer than one year, in the case of light crude, and
two years, in the case of heavy crude, duration (up to 25 years)
requires an exporter to obtain an export license from the NEB.
The issue of such a license requires the approval of the Governor
in Council. Natural gas exported from Canada is also subject to
similar regulation by the NEB. Exporters are free to negotiate
prices and other terms with purchasers, provided that the export
contracts in excess of two years must continue to meet certain
criteria prescribed by the NEB. The governments of Alberta and
British Columbia also regulate the volume of natural gas which
may be removed from those provinces for consumption elsewhere
based on such factors as reserve availability, transportation
arrangements and market considerations.
Environmental Regulation. The oil and natural gas industry is
subject to environmental regulation pursuant to local, provincial
and federal legislation. Environmental legislation provides for
restrictions and prohibitions on releases or emissions of various
substances produced or utilized in association with certain oil
and gas industry operations. In addition, legislation requires
that well and facility sites be abandoned and reclaimed to the
satisfaction of provincial authorities. A breach of such
legislation may result in the imposition of fines and penalties.
QMR is committed to meeting its responsibilities to protect the
environment wherever it operates and anticipates making increased
expenditures of both a capital and expense nature as a result of
the increasingly stringent laws relating to the protection of the
environment. QMR's unreimbursed expenditures in 1999 concerning
such matters were immaterial, but QMR cannot predict with any
reasonable degree of certainty its future exposure concerning
such matters. QMR is not aware of any currently pending
environmental legislation or regulation in Canada that would have
a material adverse effect on the Company if enacted.
Investment Canada Act. The Investment Canada Act requires
Government of Canada approval, in certain cases, of the
acquisition of control of a Canadian business by an entity that
is not controlled by Canadians. In certain circumstances, the
acquisition of natural resource properties may be considered to
be a transaction requiring such approval.
-10-
<PAGE>
Insurance Coverage Maintained with Respect to Operations
Principally through shared arrangements with Questar, the Company
maintains insurance policies covering its operations in amounts and
areas of coverage normal for a company of its size in the oil and gas
exploration and production industry. These include, but are not
limited to, worker's compensation, employers' liability, automotive
liability, certain environmental claims and general liability. In
addition, umbrella liability and operator's extra expense policies are
maintained. All such insurance is subject to normal deductible
levels.
Competition
The oil and gas business is highly competitive. The Company faces
competition in all aspects of its business, including, but not limited
to acquiring reserves, leases, licenses and concessions; obtaining
goods, services and labor needed to conduct its operations and manage
the Company; and marketing its oil and gas. Intense competition
occurs with respect to marketing, particularly of natural gas. The
Company's competitors include multinational energy companies, other
independent producers and individual producers and operators. Many
competitors have greater financial and other resources than the
Company.
Seasonal Nature of Business
Generally, but not always, the demand for natural gas decreases during
the summer months and increases during the winter months. Seasonal
anomalies such as mild winters sometimes lessen this fluctuation. In
addition, pipelines, utilities, local distribution companies and
industrial users utilize natural gas storage facilities and purchase
some of their anticipated winter requirements during the summer. This
can also lessen seasonal demand fluctuations.
Natural Gas and Oil Marketing
The Company markets substantially all of its own natural gas and oil
production. The revenues generated by the Company's operations are
highly dependent upon the prices of, and demand for, oil and gas. The
price received by the Company for its crude oil and natural gas
depends upon numerous market factors, the majority of which are beyond
the Company's control, including economic conditions in the United
States and elsewhere, the world political situation, OPEC actions, and
governmental regulation. The fluctuation in world oil prices
continues to reflect market uncertainty regarding the balance of world
demand for and supply of oil and gas. The fluctuation of natural gas
prices reflects the seasonal swings of storage inventory, weather
conditions, and increasing utilization of natural gas for electric
generation as it affects overall demand. Decreases in the prices of
oil and gas have had, and could have in the future, an adverse effect
on the Company's development and exploration programs, proved
reserves, revenues, profitability and cash flow. See "Item 2.
Financial Information - Market Risk."
Customers
QMR sells its gas production to a variety of customers including
pipelines, gas marketing firms, industrial users and local
distribution companies. Existing gathering systems and interstate and
intrastate pipelines are used to consummate gas sales and deliveries.
The principal customers for QMR's crude oil production are refiners,
remarketers and other companies, some of which have pipeline
facilities near the producing properties. In the event pipeline
facilities are not conveniently available, crude oil is trucked to
storage, refining or pipeline facilities.
-11-
<PAGE>
Employees and Offices
As of October 1, 2000, the Company had 423 full-time employees. None
of the Company's employees are represented by organized labor unions.
The Company also engages independent consulting petroleum engineers,
environmental professionals, geologists, geophysicists, landmen and
attorneys on a fee basis.
The Company's executive offices are located at 180 East 100 South, P.
O. Box 45601, Salt Lake City, Utah 84145-0601, and its telephone
number is (801) 324-2600. Regional operating offices are also
maintained in Denver, Colorado; Oklahoma City, Oklahoma; Tulsa,
Oklahoma; Rock Springs, Wyoming; and Calgary, Alberta.
ITEM 2. FINANCIAL INFORMATION
Selected Financial Data
The following tables sets forth certain selected financial data of the
Company. This information should be read in conjunction with the
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" included in this item, and the Consolidated
Financial Statements and the notes thereto included in "Item 13.
Financial Statements and Supplementary Data." The annual financial
statements of QMR included in Item 13 of this Form 10 have been
audited by Ernst & Young LLP, independent auditors, as experts in
accounting and auditing. Information disclosed in the following table
for the three months ended March 31, 2000 and 1999, and for the years
ended December 31, 1996 and 1995 has not been audited.
<TABLE>
<CAPTION>
For the Three Months
Ended March 31, For the Year Ended December 31,
2000 1999 1999 1998 1997 1996 1995
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues $141,761 $115,846 $498,311 $458,272 $523,640 $484,080 $309,466
Write-down of full cost
oil and gas properties 31,000 6,000
Write-down of gas gathering
properties 3,000
Operating income 25,675 14,343 76,778 25,629 54,837 64,688 43,853
Debt Expense 5,370 4,263 17,363 12,631 10,882 8,699 6,323
Income from continuing
operations 15,049 8,253 45,866 16,725 39,111 42,447 31,654
Loss from discontinued
operations (563) (1,021) (322)
Net Income 15,049 8,253 45,866 16,162 38,090 42,125 31,654
Net Cash provided from
operating activities 31,132 36,971 140,857 127,513 136,935 83,309 79,596
Net cash used in investing
activities 80,027 12,789 94,426 246,689 81,292 184,453 17,606
Net cash provided from (used
in) financing activities 51,448 (21,510) (48,281) 120,060 (54,615) 97,508 (63,200)
Cash dividends paid to
Questar 4,325 4,150 16,600 15,900 16,325 14,500 13,000
At March 31, At December 31,
2000 1999 1999 1998 1997 1996 1995
(In Thousands)
Total assets $918,334 $804,227 $847,891 $815,153 $696,675 $696,754 $457,620
Short-term debt 49,700 111,400 24,500 121,800 44,300 78,000 14,000
Long-term debt 293,074 186,008 264,894 181,624 133,387 120,000 53,000
Common equity 399,555 365,715 387,834 359,638 359,283 337,666 282,144
</TABLE>
-12-
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion and analysis addresses changes in the
Company's financial condition and results of operations.
Results of Operations -
<TABLE>
<CAPTION>
Three Months Ended
March 31, Year Ended December 31,
2000 1999 1999 1998 1997
(In Thousands)
<S> <C> <C> <C> <C> <C>
Operating Income -
Revenues
Natural gas sales $36,772 $28,011 $125,245 $98,767 $89,489
Oil and natural gas
liquids sales 15,198 7,959 41,521 36,722 53,722
Cost of service gas
operations 17,730 15,658 61,705 61,448 52,950
Energy marketing 63,760 58,004 243,296 234,565 297,413
Gas gathering and 7,099 4,924 22,341 21,954 25,998
processing
Other 1,202 1,290 4,203 4,816 4,068
Total revenues 141,761 115,846 498,311 458,272 523,640
Operating expenses
Energy purchases 63,893 56,392 239,201 230,462 291,851
Operating and
maintenance 22,918 20,169 79,916 73,763 72,958
Depreciation and
amortization 20,977 19,605 78,608 71,377 67,078
Write-down of full
cost oil and gas
properties 31,000 6,000
Write-down of gas
gathering properties 3,000
Other taxes 7,314 5,128 21,516 24,988 25,569
Wexpro settlement
agreement -
Oil income sharing 984 209 2,292 1,053 2,347
Total operating
expenses 116,086 101,503 421,533 432,643 468,803
Operating income $ 25,675 $ 14,343 $ 76,778 $ 25,629 $ 54,837
Operating Statistics -
Production volumes
(excluding cost of
service activities)
Natural gas (MMcf) 16,950 15,048 62,712 51,309 47,442
Oil and NGL (MBbl) 554 606 2,311 2,340 2,377
Production revenue
(excluding cost of
service activities)
Natural gas (per Mcf) $ 2.17 $ 1.86 $ 2.00 $ 1.92 $ 1.89
Oil and NGL (per Bbl) $ 21.64 $ 10.65 $ 13.92 $ 12.70 $ 17.77
Wexpro investment base,
net of deferred income
taxes (in thousands) $109,690 $ 98,343 $108,890 $ 97,594 $ 72,867
Energy-marketing volumes
(in thousands of
equivalent Dth) 27,025 34,159 112,982 113,513 142,601
Natural gas-gathering
volumes (MDth)
For unaffiliated
customers 21,778 20,291 84,961 72,908 57,586
For Questar Gas 9,853 8,237 32,050 29,893 28,506
For other affiliated
customers 5,164 4,559 19,659 17,720 17,679
Total gathering 36,795 33,087 136,670 120,521 103,771
Gathering revenue (per Dth) $0.14 $0.16 $0.15 $0.16 $0.21
</TABLE>
-13-
<PAGE>
Revenues
Revenues from natural gas sales were 27% higher in 1999 compared with
1998. Gas production rose 22% and selling prices were 4% higher.
First quarter revenues from selling natural gas increased $8.8 million
as a result of a 17% increase in price and a 13% increase in volumes
of gas produced. Production benefitted from a successful development
drilling program and acquisition of Canadian producing properties in
the first quarter of 2000. First quarter Canadian gas production grew
94% to 1.6 Bcf , while U.S. production increased 8% to 15.4 Bcf.
Revenues from selling oil and natural gas liquids, excluding cost of
service activities, climbed 8% in 1999 due to a 10% increase in
average selling prices. A 103% increase in the average price of oil
and NGL more than offset the effect of lower production to result in a
86% increase in first quarter revenues. Production of oil and NGL
decreased in the first quarter as a result of selling nonstrategic
properties in the fourth-quarter of 1999. Higher prices also
benefitted the operations of liquids-extraction plants that
experienced improved results for the first quarter of 2000.
Revenues and product purchases for marketing activities both increased
4% in 1999 compared with 1998 resulting in no change in the margin
year to year. In 1999, the Company received refunds from pipelines as
a result of orders issued by FERC. Marketing volumes were unchanged
year to year. While commodity prices increased during the first
quarter of 2000, marketing volumes declined 21% due to decreased oil
trading activity and the impact of unfavorable fixed transportation
rates for natural gas.
Revenues from gas gathering and processing grew 2% in 1999. Gathering
volumes increased 13% because of increased drilling and gas production
in the Rocky Mountain region. A change in the terms of the gathering
contract with Questar Gas reduced the gathering rate from $.21 in 1997
to $.16 per Dth in 1998 and also resulted in a $3 million write-down
of gathering assets in 1997 due to the projected reduction of
gathering revenues. Volumes of gas gathered increased 11% in the
first quarter of 2000, reflecting more production in the areas served
by the Company.
During 1999, QMR had forward sale contracts in place on approximately
59% of its gas production at an average price of $2.03 per Mcf, net
back to the well. Approximately 56% of oil production, excluding cost
of service oil production, was hedged at an average price of $15.02
per barrel, net back to the well, which was equivalent to $16.33 per
barrel using the West Texas Intermediate benchmark. At December 31,
1999, approximately 52% of Company owned gas production in 2000 and
2001 was under hedging contracts with prices, net back to the well,
between $2.15 and $2.23 per Mcf. Oil production in 2000 and 2001 is
hedged at $17.22 to $17.67 per barrel, net back to the well, on
approximately 84% of production, excluding cost of service production.
As of the end of the first quarter 2000, about 40% of natural gas
production through the end of 2001 is hedged at an average price of
$2.15 per Mcf, net back to the well. Approximately 80% of oil
production, excluding cost of service production, is hedged at an
average price of $17.22 per barrel, net back to the well through the
end of 2001.
Expenses
A 31% drop in the average selling price of oil and NGL caused a $31
million write-down of oil and gas properties in the fourth quarter of
1998 under full cost accounting rules. The write-down reduced income
by $18.5 million after taxes. Revenues for QMR decreased 12% in 1998
compared with 1997, due primarily to lower marketing revenues and
lower selling prices for oil and NGL. Natural gas production
increased 8% primarily as a result of producing properties acquired in
September 1998. Lower commodity prices in Canada caused a $6 million
full cost write-down in 1997.
Operating and maintenance expenses were higher in the three-month
period of 2000 when compared with the 1999 period primarily because of
increased investment in producing properties. The Company added
approximately 61.1 Bcfe of reserves and 800 wells with the first
quarter 2000 acquisition of Canor. Operating and maintenance expenses
increased 8% in 1999 primarily due to an increase in the number of
gas and oil properties. Production costs in aggregate increased 10%
in 1999 compared with 1998, but were 6% lower on an equivalent Mcf
basis.
The combined U.S. and Canadian full cost amortization rate was $.80
per Mcfe for the first quarter of 2000 compared with $.83 for the
comparable 1999 quarter. The lower rate was due to successfully
adding reserves through drilling and
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<PAGE>
selling nonstrategic properties. Higher production volumes more than
offset the lower amortization rates and resulted in increased
amortization expense in the first quarter of 2000 when compared with
the corresponding 1999 period. The full cost amortization rate
decreased to $.80 per Mcfe for 1999, down from $.85 in 1998.
However, depreciation and amortization expense increased 10% in 1999
because of higher gas production.
QMR achieved a five-year average full cost finding and acquisition
cost of $.90 per Mcfe in 1999 compared with $.95 per Mcfe in 1998.
With respect to Wexpro's cost of service activities, the five-year
finding cost was $.64 per Mcfe and $.80 per Mcfe in 1999 and 1998,
respectively.
Debt expense was $10.9 million, $12.6 million, and $17.4 million in
1997, 1998, and 1999, respectively. Debt expense was higher in 1999
and 1998 when compared with the corresponding prior year because of
higher levels of borrowings used to finance capital expansion. Debt
expense was higher in the first quarter of 2000 compared to the 1999
period primarily because of increased borrowing for capital
expenditures.
Effective income tax rates are below the combined federal, state and
foreign statutory rate of about 40% primarily due to a portion of the
Company's gas production qualifying for nonconventional fuel tax
credits, which reduced income tax expense by $5.3 million in 1999,
$5.7 million in 1998, and $6.6 million in 1997. The effective income
tax rate for the first quarter was 32.8% in 2000 and 24.3% in 1999.
The Company recognized $1.1 million of production-related tax credits
in the first quarter of 2000 and $1.3 million in the first quarter of
1999.
Operating Income and Net Income
QMR's operating income and net income increased 36% and 32%,
respectively, in 1999 compared with 1998, excluding a 1998 full cost
write-down. Primary factors were an increase in gas production,
higher commodity prices and an increase in the Wexpro investment base.
QMR's operating income and net income rose 79% and 82%, respectively,
in the first quarter of 2000 when compared with the first quarter of
1999, due primarily to increased production of natural gas and higher
prices received for gas, oil and NGL. Other factors include higher
earnings from Wexpro and gas gathering and processing operations.
Wexpro's net income increased $.7 million to $5.8 million in the first
quarter of 2000. Wexpro expanded its investment in development
drilling prospects in response to higher regional demand. Wexpro's
investment base, net of deferred income taxes, grew 12% to $108.9
million as of December 31, 1999, through its successful development
drilling program. Wexpro's investment base represents the unamortized
portion of the dollars invested in those assets that are regulated by
the Wexpro settlement agreement. Wexpro's effective after-tax return
on investment in those properties was 18.9% at the end of the year. A
summary of the Wexpro settlement agreement is provided in Note 10 of
the Notes to Consolidated Financial Statements under Item 13 of this
Form 10.
Gas gathering and processing and energy-marketing operations reported
$.9 million in combined earnings for the first quarter of 2000 versus
$.8 million a year ago. Volumes of gas gathered increased 11% in the
first three months of 2000, reflecting more production in the areas
served. Higher prices benefitted the operations of gas processing
plants which experienced improved results for the first quarter of
2000. The plants extract and sell liquids from the natural gas
stream. Increased commodity prices caused revenues from
energy-marketing activities to be higher, but the impact of
unfavorable fixed transportation rates and the settlement of gas
imbalances resulted in an $841,000 after-tax loss for energy-marketing
activities in the first quarter of 2000.
Reserves
Excluding activities with respect to cost of service related reserves,
QMR achieved a 131% reserve replacement ratio in 1999. The reserve
replacement ratio measures the extent to which annual oil and gas
production volumes are replaced in the current year through
acquisitions, discoveries, development drilling, and revisions of
prior estimates, less any sales of reserves that may have occurred.
In 1999, reserve additions, revisions, and purchases amounted to 134
Bcfe with 108% of the reserve replacement ratio coming from drilling
results and 23% from purchases. In 1999, QMR sold 34 Bcfe
-15-
<PAGE>
of nonstrategic reserves mostly in the Permian Basin and Kansas with
combined daily production of 4.3 MMcf of gas and 1,100 barrels of oil.
The sale proceeds helped reduce the full cost amortization rate in the
fourth quarter of 1999. Reserve replacement in 1998 was 260% and 170
Bcfe, primarily the result of acquiring an estimated 150 Bcfe of
proved oil and gas reserves, primarily in Oklahoma, as well as in
Texas, Arkansas and Louisiana. The proved reserves associated with
properties qualifying for nonconventional fuel credits are not
dependent upon the existence of the income tax credits to be
economically producible and are not a significant part of QMR's proved
reserves. The expiration of these credits on December 31, 2002 is not
expected to have a significant impact on future operations or proved
reserves.
Liquidity and Capital Resources -
Operating Activities: Net cash provided from operating activities was
derived from the following:
<TABLE>
<CAPTION>
For the Three Months
Ended March 31, For the Year Ended December 31,
2000 1999 1999 1998 1997
(In Thousands)
<S> <C> <C> <C> <C> <C>
Net Income $15,049 $ 8,253 $ 45,866 $ 16,162 $ 38,090
Non-cash transactions 20,581 20,053 90,077 100,106 77,132
Changes in working capital (4,498) 8,665 4,914 11,245 21,713
Net cash provided from
operating activities $31,132 $36,971 $140,857 $127,513 $136,935
</TABLE>
Net cash provided from operating activities in the first quarter of
2000 was $5.8 million less than was generated in the first quarter of
1999. A decrease in cash flow from changes in operating assets and
liabilities as a result of payments made on hedging account margin
calls and timing differences in payments of general accounts payable
more than offset the effects of higher net income.
Net cash provided from operating activities increased 10% in 1999
primarily due to higher net income. Cash flows from accounts
receivable declined, representing increases in balances in 1999, due
to higher commodity prices. The write-downs of oil and gas properties
in both 1998 and 1997 and their effect on deferred income taxes were
noncash transactions.
Investing Activities: Capital expenditures and other investing
activities amounted to $134.3 million in 1999, $254.5 million in 1998,
and $92.3 million in 1997. Capital expenditures were $80.3 million in
the first quarter of 2000, which includes approximately $61 million
plus the assumption of $5.4 million in short-term debt for the
purchase of Canor. In the first quarter of 1999, capital expenditures
totaled $14.1 million. Following is a summary of capital expenditures
for 1999 and 1998, and a forecast for 2000:
-16-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
2000 1999 1998
Forecast
(In Thousands)
<S> <C> <C> <C>
Capital expenditures and other
investing activities
Exploratory drilling $ 3,100 $ 1,538 $ 5,898
Development drilling 83,400 64,642 60,402
Other exploration 4,100 19,464 6,789
Reserve acquisitions 61,500 3,704 158,000
Production 13,500 12,856 8,434
Gathering and processing 4,800 12,703 11,046
General and other 300 19,362 3,977
$175,700 $134,269 $254,546
</TABLE>
Capital expenditures in 1999 were primarily comprised of exploration
and development of gas and oil reserves and a $9.1 million equity
contribution in a partnership that operates a liquids processing
plant. QMR participated in drilling 235 wells (93 net wells) in 1999
that resulted in 167 gas wells, 10 oil wells, 19 dry holes and 39
wells in progress at year end. The 1999 drilling success rate was
90%.
Financing Activities: Net cash flow provided from operating
activities was sufficient to fund 1999 capital expenditures. The
Company used the proceeds of long-term debt and collection of notes
receivable to reduce short-term borrowings and refinance
reserved-based, long-term debt used to acquire gas and oil reserves in
1998. Proceeds from a sale of nonstrategic gas and oil properties
were placed in an escrow account pending a reinvestment in
strategic-producing properties.
In 1999, QMR entered into a long-term senior-revolving-credit facility
with a syndication of banks. The credit facility currently has a $300
million capacity. QMR had outstanding $293.1 million and $264.9
million as of March 31, 2000 and December 31, 1999, respectively,
under this arrangement. Net working capital was negative at March 31,
2000 and December 31, 1999, because of short-term borrowings. These
borrowings are typical of a company expanding operations.
In the first quarter of 2000, QMR financed capital expenditures,
including the acquisition of Canor, through borrowings from Questar,
from an existing long-term debt arrangement, and from net cash
provided from operating activities. Debt balances owed to Questar as
of March 31, amounted to $49.7 million in 2000 and $75.7 million in
1999, net of notes receivable from Questar. QMR intends to finance
2000 capital expenditures through net cash provided from operations,
borrowings from Questar, and borrowings under QMR's existing long term
credit facility.
QMR's consolidated capital structure consisted of 41% long-term debt
and 59% common shareholder's equity at December 31, 1999, and 42%
long-term debt and 58% common shareholder's equity at March 31, 2000.
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 Canadian operation
that subjects it to exchange-rate risk. QMR also has reserved certain
volumes of pipeline capacity for which it is obligated to pay $3
million annually for the next seven years, whether or not it is able
to market the capacity to others.
Energy Price Risk Management: Energy-price risk is a function of
changes in commodity prices as supply and demand fluctuate. QMR bears
a majority of the risk associated with changes in commodity prices. A
primary objective of
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<PAGE>
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.
At March 31, 2000, hedge contracts held by QMR covered price exposure
for about 58.6 million Dth and 2.1 MMBbl of oil. QMR held hedge
contracts covering the price exposure for about 72.1 million Dth of
gas and 2.4 MMBbl of oil at December 31, 1999. A year earlier the
contracts covered 45.3 million Dth of natural gas and 464,000 barrels
of oil. The hedging contracts exist for a significant share of QMR
owned gas and oil production and for a portion of gas-marketing
transactions. Hedge contracts at March 31, 2000 and December 31,
1999, had terms extending through December 2001, with about 53% and
65%, respectively, expiring by the end of 2000.
The mark-to-market adjustment of gas and oil price-hedging contracts
at March 31, 2000, was a negative $31.5 million. A 10% decline in gas
and oil prices would cause a positive $18.0 million mark-to-market
adjustment resulting in a negative $13.5 million balance on that date.
Conversely, a 10% increase in prices results in a $18.6 million
negative mark-to-market adjustment resulting in a negative $50.2
million balance as of March 31, 2000. Comparatively, 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 would cause a positive $16.7 million mark-to-market
adjustment resulting in a $10.5 million balance. A 10% increase in
prices results in a $16.3 million negative mark-to-market adjustment
resulting in a negative $22.5 million balance. The fair value of
hedging contracts at December 31, 1998, was $6 million. A 10% decline
in gas and oil prices would cause the fair value of the contracts to
increase by $3.9 million. A 10% increase in prices results in a $4.1
million lower fair value calculation. The mark-to-market calculations
used energy prices posted on the NYMEX for the indicated measurement
dates. These sensitivity calculations do not consider the effect of
gains or losses recognized on the underlying physical side of these
transactions, which should largely offset the change in value.
Interest Rate Risk Management: The Company owed $293.1 million of
variable-rate long term debt at March 31, 2000, $264.9 million at
December 31, 1999, and $181.6 million at December 31, 1998. The book
value of variable rate debt approximates its fair value. If interest
rates change by 10%, interest costs would increase or decrease about
$1.7 million in 1999 and $1.1 million in 1998, correspondingly. This
sensitivity calculation does not represent the cost to retire the debt
securities.
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. A 10% change
in prices would either increase or decrease the value by $1.0 million
at December 31, 1999 and $1.3 million at March 31, 2000.
Foreign Currency Risk Management: The Company does not hedge the
Canadian currency exposure of its Canadian operation's net assets.
The net assets of the foreign operation were negative at December 31,
1999 and March 31, 2000. Long-term debt held by the foreign
operation, amounting to $59.9 million (U.S.) at December 31, 1999 and
$66.6 million (U.S.) at March 31, 2000, is expected to be repaid from
future operations of the foreign company. As more fully described
under "Item 3. Properties - Recent Developments" herein, QMR expanded
its foreign operations during January 2000 when it purchased 100% of
the outstanding common stock of Canor for approximately $61 million
(U.S.) plus the assumption of $5.4 million (U.S.) of short-term debt.
Litigation -
QMR, or one of its subsidiaries, is a party to various legal actions
arising in the normal course of business. QMR and Questar are also
among the named defendants in a class action lawsuit (Bridenstine vs.
Kaiser-Francis Oil Company) that claims damages that have at times
been estimated in excess of $80 million, plus punitive damages. See
"Item 8. Legal Proceedings." The Company regularly reviews potential
liabilities related to legal proceedings and records appropriate
accruals after considering estimates of the outcome of such matters
and the Company's experience in contesting, litigating, and settling
similar matters. While it is not currently possible to predict or
determine the outcome of the various legal actions, it is the opinion
of management that the outcomes will not have a material adverse
effect on the Company's future results of operations, financial
position, or liquidity.
-18-
<PAGE>
Year 2000 Issues -
Questar established a team to address the issue of computer programs
and embedded computer chips being unable to distinguish between the
year 1900 and the year 2000 ("Y2K"). The team identified 55 projects
among Questar and its affiliated companies that were assessed,
remediated, tested, and determined to be completed. In the process,
Questar employees contacted more than 8,000 vendors and suppliers to
assess their readiness to meet obligations to Questar. The cost of
the Y2K project was approximately $5.1 million and QMR's share of
those costs was $.4 million.
The Company did not experience a disruption of operations because of
Y2K. Preparation for Y2K provided several benefits. The Company
completed an inventory of its primary systems and a testing
laboratory. Systems were tested and remediated where necessary. The
testing laboratory will become an important part of the
information-technology management. In response to the Y2K challenge,
business contingency plans were revised and successfully tested.
ITEM 3. PROPERTIES
Reserves
The following table sets forth the Company's estimated proved
reserves, the 10% present value of the estimated future net revenues
therefrom and the standardized measure of discounted net cash flows as
of December 31, 1999. QMR's reserves were estimated by Ryder Scott
Company, H. J. Gruy and Associates, Inc., Netherland, Sewell &
Associates, Inc., Malkewicz Hueni Associates, Inc., and Gilbert
Laustsen Jung 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.
<TABLE>
<CAPTION>
December 31, 1999
United States Canada Total
<S> <C> <C> <C>
Estimated proved reserves
Natural gas (Bcf) 493.8 20.7 514.5
Oil and NGL (MMBbls) 11.1 2.8 13.9
Proved developed reserves (Bcfe) 471.4 32.5 503.9
Present value of estimated future net
revenues before future income taxes
discounted at 10% (in thousands) (1) $509,522 $48,568 $558,090
Standardized measure of discounted net
cash flows (in thousands)(2) $402,771 $41,663 $444,434
_______
</TABLE>
(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%.
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 therefrom are affected by natural gas and oil prices,
which have fluctuated widely in recent years. There are numerous
uncertainties
-19-
<PAGE>
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 represents only
estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil that
cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of
engineering and geological interpretation and judgement. As a result,
estimates of different engineers, including those used by the Company,
may vary. In addition, estimates of reserves are subject to revision
based upon actual production, results of future development and
exploration activities, prevailing natural gas and oil prices,
operating costs and other factors, which revisions may be material.
Accordingly, reserve estimates are often different from the quantities
of natural gas and oil that are ultimately recovered and are highly
dependent upon the accuracy of the assumptions upon which they are
based.
Reference should be made to Note 13 of the Notes to Consolidated
Financial Statements included in Item 13 of this document 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 estimates of oil and gas reserves as of
December 31, 1999, with the U. S. Department of Energy's Energy
Information Administration ("EIA") on Form EIA-23. Reserve estimates
filed on Form EIA-23 are based upon the same underlying technical and
economic assumptions as the estimates of the Company's reserves
included herein. However, the EIA requires reports to include the
interests of all owners in wells that the Company operates and to
exclude all interests in wells that the Company does not operate.
The following charts illustrate QMR's reserve statistics for the years
ended December 31, 1995 through 1999:
<TABLE>
<CAPTION>
Oil and Gas Reserves (Bcfe)*
Year Year-End Reserves Annual Production Reserve Life (Years)
<S> <C> <C> <C>
1995 311.3 42.5 7.3
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
</TABLE>
* Does not include cost of service reserves managed and developed
by Wexpro for Questar Gas.
<TABLE>
<CAPTION>
Proportion of Proved Developed to Proved Reserves
and Proportion of Gas Reserves (Bcfe)*
<S> <C> <C> <C> <C>
Year Total Proved Proved Developed Developed Natural Gas Percentage of
Reserves Reserves Percent of Total Proved Reserves
1995 311.3 293.8 94% 83%
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%
</TABLE>
* Does not include cost of service reserves managed and developed by Wexpro
for Questar Gas.
-20-
<PAGE>
Geographic Diversity of Producing Properties
The following table summarizes proved reserves by the Company's major
operating areas at December 31, 1999:
<TABLE>
<CAPTION>
Proved Reserves* % of Total
(Bcfe)
<S> <C> <C>
Mid-Continent 335.1 56.1%
Rocky Mountain Region
(exclusive of Pinedale) 139.7 23.3%
Pinedale Anticline 54.7 9.2%
Western Canada Sedimentary Basin 37.4 6.3%
San Juan Basin 30.7 5.1%
597.6 100.0%
</TABLE>
* 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 three
months ended March 31, 2000 and 1999 and for the years ended December 31,
1999, 1998, and 1997, respectively:
<TABLE>
<CAPTION>
Three Months Ended
March 31, Year Ended December 31,
2000 1999 1999 1998 1997
<S> <C> <C> <C> <C> <C>
United States (excluding
cost of service activities)
Volumes produced and sold
Gas (Bcf) 15.4 14.2 59.8 48.6 44.3
Oil and NGL (MMBbls) .4 .5 1.9 1.9 2.1
Sales Prices:
Gas (per Mcf) $ 2.20 $ 1.88 $ 2.02 $ 1.95 $ 1.92
Oil and NGL (per Bbl) $21.66 $10.70 $13.31 $12.41 $17.90
Production costs per Mcfe $ .62 $ .60 $ .59 $ .64 $ .65
Canada
Volumes produced and sold
Gas (Bcf) 1.6 .8 2.9 2.7 3.1
Oil and NGL (MMBbls) 0.2 0.1 0.4 0.4 0.3
Sales Prices:
Gas (per Mcf) $ 1.90 $ 1.48 $ 1.61 $ 1.40 $ 1.35
Oil and NGL (per Bbl) $21.58 $10.47 $16.56 $14.09 $16.80
Production costs per Mcfe $ .72 $ .61 $ .67 $ .58 $ .52
</TABLE>
-21-
<PAGE>
Productive Wells
The following table summarizes the Company's productive wells,
including productive cost of service wells included in Wexpro's
investment base, as of December 31, 1999:
<TABLE>
<CAPTION>
Productive Wells (1) (2) (3)
Gas Wells Oil Wells Total Wells
Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C>
United States 3,228 1,220.1 1,249 484.5 4,477 1,704.6
Canada 82 22.3 92 27.2 174 49.5
Total: 3,310 1,242.4 1,341 511.7 4,651 1,754.1
____________
</TABLE>
(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 134 gross wells with
multiple completions.
(3) Wexpro's investment base represents the dollars invested in
development drilling on cost of service properties that are
regulated by the Wexpro settlement agreement. A summary of
the Wexpro settlement agreement is provided in Note 10 of the
Notes to Consolidated Financial Statements under Item 13
herein.
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, 1999. "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.
-22-
<PAGE>
<TABLE>
<CAPTION>
Leasehold Acreage - December 31, 1999
Developed (1) Undeveloped (2) Total
Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C>
United States
Arizona - - 480 450 480 450
Arkansas 37,729 16,569 8,984 4,478 46,713 21,047
California 80 28 35,011 15,322 35,091 15,350
Colorado 176,604 123,974 207,853 105,449 384,457 229,423
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 7,761 2,471 7,895 2,605
Kentucky - - 14,461 5,468 14,461 5,468
Louisiana 15,246 9,992 251 251 15,497 10,243
Michigan - - 6,200 1,266 6,200 1,266
Minnesota - - 313 104 313 104
Mississippi 25,706 21,408 - - 25,706 21,408
Montana 25,445 10,707 319,588 58,438 345,033 69,145
Nevada 320 280 680 543 1,000 823
New Mexico 92,497 68,188 31,765 9,313 124,262 77,501
North Dakota 1,333 375 145,841 21,580 147,174 21,955
Ohio - - 202 43 202 43
Oklahoma 1,570,227 294,207 52,736 33,296 1,622,963 327,503
Oregon - - 43,869 7,671 43,869 7,671
South Dakota - - 204,558 107,988 204,558 107,988
Texas 167,690 60,170 50,571 39,515 218,261 99,685
Utah 45,712 35,001 109,180 43,818 154,892 78,819
Washington - - 26,631 10,149 26,631 10,149
West Virginia 969 115 - - 969 115
Wyoming 216,991 138,681 445,315 271,418 662,306 410,099
Total U.S. 2,376,855 779,868 1,772,353 754,138 4,149,208 1,534,006
Canada
Alberta 42,080 11,910 61,760 18,541 103,840 30,451
British Columbia 34,259 8,855 39,169 22,977 73,428 31,832
Total Canada 76,339 20,765 100,929 41,518 177,268 62,283
Total Acreage 2,453,194 800,633 1,873,282 795,656 4,326,476 1,596,289
</TABLE>
(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 1,873,282 gross and 795,656 net undeveloped
acres, 123,501 gross and 36,105 net acres are held by
production from other leasehold acreage.
-23-
<PAGE>
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:
<TABLE>
<CAPTION>
Acres Expiring
Gross Net
<S> <C> <C>
Twelve Months Ending:
December 31, 2000 91,504 39,918
December 31, 2001 96,177 31,322
December 31, 2002 39,971 13,082
December 31, 2003 95,043 52,366
December 31, 2004 and later 1,550,587 658,968
</TABLE>
Drilling Activity
The following table summarizes the number of development and
exploratory wells drilled by the Company, including cost of service
development drilling conducted by Wexpro, during the years indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C> <C> <C> <C>
Gross Net Gross Net Gross Net
Development Wells
United States:
Completed as natural gas wells 159 78.4 105 54.6 82 27.4
Completed as oil wells 5 2.4 29 1.0 64 6.6
Dry holes 15 6.1 12 3.7 18 5.7
Waiting on completion 29 - 13 - 26 -
Drilling 6 - 9 - 15 -
Canada:
Completed as natural gas wells 7 1.2 4 0.9 4 0.9
Completed as oil wells 5 1.9 12 4.0 4 1.3
Dry holes 2 1.3 4 1.2 3 0.9
Waiting on completion 2 - 2 - 6 -
Drilling - - 1 - 2 -
Total Development Wells 230 91.3 191 65.4 224 42.8
</TABLE>
-24-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells
United States:
Completed as natural gas wells 1 0.2 5 1.6 4 1.6
Completed as oil wells - - 1 .6 - -
Dry holes 2 1.1 4 1.4 1 0.3
Waiting on completion 1 - - - 2 -
Drilling 1 - - - - -
Canada:
Completed as natural gas wells - - - - 1 -
Completed as oil wells - - 1 .3 2 0.1
Dry holes - - 3 1.4 - 0.7
Waiting on completion - - - - 1 -
Total Exploratory Wells 5 1.3 14 5.3 11 2.7
Total Wells 235 92.6 205 70.7 235 45.5
</TABLE>
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% 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.
Recent Developments
Canadian Acquisition - On January 26, 2000, the Company completed the
acquisition of all of the outstanding shares of Canor Energy Ltd., an
oil and gas exploration company based in Calgary, Alberta, Canada.
Canor owns and/or
-25-
<PAGE>
operates more than 800 wells located primarily in the province of
Alberta, as well as in the provinces of British Columbia and
Saskatchewan. The combination of Canor with Celsius Ltd. will expand
the Company's reported proved reserves by approximately 61.1 Bcfe, or
10%, and add about 150,000 net acres to the Company's Canadian
undeveloped leasehold inventory, principally in the province of
Alberta. The purchase price for the cash transaction was
approximately $61 million (U.S.) plus the assumption of $5.4 million
(U.S.) of short-term debt.
The Canor acquisition will provide a broader operating and financial
base for the Company's Canadian activities, particularly in the areas
of exploration and exploitation opportunities. It is anticipated that
Celsius Ltd. and Canor will be amalgamated into a single entity at
some point in the future.
Pinedale Project - In January 2000, Questar E&P and Wexpro completed a
high-volume producing well in the Company's Pinedale Anticline
development in Sublette County, Wyoming. The Mesa Unit No. 3 produced
11.4 MMCF of natural gas into a pipeline and 113 barrels of oil from
the Lance Formation during the initial 24-hour period. The Lance
Formation in the Pinedale Anticline area is a geologic structure
comprised of many discrete sandstone intervals found at depths between
8,500 and 13,500 feet. The Mesa Unit No. 3 was drilled to a total
measured depth of 13,055 feet and was fracture-stimulated (a
production enhancement technique) in 11 individual sandstone
intervals. Questar E&P and Wexpro have a combined 93.8% working
interest in the well. While this is not a new discovery -- the first
test well into the Pinedale Anticline was drilled in 1939 and Questar
drilled its first acreage holding well in this area in 1963 - it has
only been recently that improvements in well completion and production
enhancement technology has provided the means to attain higher
production rates from multiple sand intervals such as the Lance
Formation at a reasonable cost. The Company has completed a second
Mesa Unit well - No. 6 - located about one-half mile south of the Mesa
Unit No. 3. The second well encountered a similar number of
potentially productive sandstone intervals, and initial test results
are comparable to the Mesa Unit No. 3. A third well failed to produce
economic quantities of gas because of lower-quality reservoir rock.
The unsuccessful well does not diminish the Company's expectations for
the development potential of its 14,800 gross acres in the Mesa area
of the Pinedale Anticline where QMR subsidiaries own a combined
average 60% working interest.
As of June 30, 2000, there were eight proved developed producing wells
on the Company's acreage in the Pinedale area. Malkewicz Hueni
Associates, Inc., independent petroleum engineers, have identified an
additional 28 proved undeveloped locations, based on SEC definitions
and guidelines, on the Company's acreage. The gross reserve range for
the proved developed wells was 3.1 to 7.5 Bcfe and the gross reserve
range for the proved undeveloped locations was 3.1 to 6.4 Bcfe. An
average completed well cost of $2,350,000 was assumed for the proved
undeveloped locations. Based on 80-acre spacing, which is less dense
than the 40-acre spacing currently permitted by the State of Wyoming,
the Company estimates the potential for 130 or more drilling locations
within the Company's acreage in the Pinedale Anticline.
On July 27, 2000, the Wyoming State Office of the Bureau of Land
Management ("BLM") issued its Record of Decision ("ROD") approving the
Pinedale Anticline natural gas project under the Resource Protection
Alternative of its Environmental Impact Statement, as modified. The
ROD allows 700 producing well pads in the area, which encompasses
approximately 197,000 acres, including the Company's acreage, and does
not restrict the number of drilling rigs to be employed. The Company
is currently employing five contract drilling rigs to drill the first
five wells of an 8 to 10 well program planned for the remainder of
2000. The accelerated rate of drilling activity is necessary in order
to complete the drilling program prior to November 15, the required
date to cease drilling activity due to winter wildlife habitat
restrictions.
Office Leases
Questar E&P and Wexpro lease office space under a sublease from
Questar for its corporate headquarters at 180 East 100 South, Salt
Lake City, Utah 84145. The Company also leases regional office space
at various locations in the United States and Canada. For information
concerning the Company's lease obligations, see Note 7 of the Notes to
Consolidated Financial Statements appearing elsewhere in this Form 10.
-26-
<PAGE>
ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
All of the outstanding shares of common stock ($1.00 par value per
share) of QMR are owned by Questar, whose principal executive offices
are located at 180 East 100 South, Salt Lake City, Utah 84111.
Questar possesses sole voting and investment power with respect to
such shares of common stock.
ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS
The executive officers and directors of the Company are set forth in
the following table:
Name Position Age
R. D. Cash Chairman 58
G. L. Nordloh Presient, CEO and Director 53
S. E. Parks Vice President, Treasurer & CFO 49
M. B. McGinley Vice President 51
M. L. Owen Vice President, Administrative Services 49
C. C. Holbrook Secretary 54
Teresa Beck Director 46
P. J. Early Director 67
C. M. Heiner Director 62
W. N. Jones Director 74
R. D. Cash, 58, Chairman of the Board of Directors, Questar (May
1985); President and Chief Executive Officer and Director, Questar
(since 1977); Chairman of the Boards of Directors, all Questar
affiliates (other than Questar Energy Trading); President and Chief
Executive Officer, QMR (from April 1982 to August 1998). Mr. Cash
also serves as a Director of Zions Bancorporation and Associated
Electric and Gas Insurance Services Limited. He is a member of the
Board of Directors of the Federal Reserve Bank (Salt Lake City Branch)
of San Francisco and is a Trustee of the Salt Lake Organizing
Committee for the Olympic Winter Games of 2002.
Gary L. Nordloh, 53, President and Chief Executive Officer, QMR
(August 1998) and all subsidiaries (commencing at various times
beginning in March 1991); Vice President, QMR (May 1996 to August
1998); Executive Vice President, Questar (February 1996); Senior Vice
President, Questar (March 1991 to February 1996); Director, Questar
(October 1996); Director, QMR (May 1991), and all QMR subsidiaries
(various times beginning in June 1989). Prior to joining the Questar
organization in 1984, Mr. Nordloh was Vice President of Engineering
and Operations for Hamilton Brothers Petroleum for three years and
Division Engineering Manager (and various other assignments) for Amoco
Production Company for nine years. Mr. Nordloh received a bachelor's
degree in Petroleum Engineering from the Colorado School of Mines. He
serves on the Board of Directors of Mountain States Legal Foundation;
is Past-President of Rocky Mountain Oil and Gas Association
(1995-1997); a member of the Society of Petroleum Engineers since
1974; is Past-President of the Society of Petroleum Engineers (Denver
Section); and served as a Regional Vice President of the Independent
Petroleum Association of America from 1989 to 1995.
S. E. Parks, 49, Vice President, Treasurer and Chief Financial
Officer, Questar and all affiliates except Questar Energy Trading
(February 1996); Treasurer, Questar and affiliates (at various dates
beginning in May 1984); Director, Questar E&P (May 1996). Mr. Parks
received a B.A. degree in Accounting and a M.B.A. degree in Finance
from the University of Utah. Since joining Questar in 1974, he has
held a variety of management positions in the auditing, accounting and
financial areas. Prior to joining Questar, Mr. Parks was with the
Academic and Financial Planning Department of the University of Utah.
-27-
<PAGE>
M. B. McGinley, 51, Vice President, QMR (August 1998) and all
subsidiaries (various dates beginning in February 1990); General
Manager, Questar Energy Trading (October 1995) and Questar Gas
Management (July 2000); Director, Questar Energy Trading (August
1998). Mr. McGinley has worked for various Questar affiliates for 31
years in a variety of engineering and marketing assignments. He holds
a Bachelor of Science Degree in Chemical Engineering and a Master of
Science Degree in Mechanical Engineering from the University of Utah.
He is a registered professional engineer in Utah and Colorado and a
member of the Independent Petroleum Association of America, and Rocky
Mountain Oil and Gas Association and the Pacific Coast Gas
Association.
M. L. Owen, 49, Vice President, Administrative Services, QMR (August
1998) and all subsidiaries (various dates beginning in April 1989);
Director, Questar Energy Trading (August 1998). Mr. Owen has been
associated with QMR since its acquisition of Universal Resources
Corporation in 1987. From 1982 to 1989, he served as Treasurer of
Universal Resources. Prior to joining Universal Resources, Mr. Owen
was employed with Arthur Andersen & Co. for eight years with various
duties, including Audit Manager. He is a Certified Public Accountant,
receiving his Accounting degree from Texas Tech University. Mr. Owen
is a member of the Independent Petroleum Association of America and
the Utah Association of Certified Public Accountants.
C. C. Holbrook, 54, General Counsel, Questar (March 1999); Vice
President Questar (October 1984); Corporate Secretary, Questar and all
affiliates except Questar Energy Trading (various dates beginning in
March 1982); Director, Questar E&P and Questar Gas Management (various
dates beginning in May 1985).
Teresa Beck, 46, Director, Questar (October 1999); Director, QMR
(October 1999). Ms. Beck was President of American Stores from 1998
to 1999. She also served as American Stores' Chief Financial Officer
from 1993 to 1998. She serves as a Director of Textron, Inc. and
Albertson's Inc. and is a Trustee of Intermountain Health Care, Inc.,
The Children's Center, and the Salt Lake Organizing Committee for the
Olympic Winter Games of 2002.
P. J. Early, 67, Director, QMR (August 1995); Director, Questar
(August 1995). Mr. Early served as Vice Chairman of Amoco Corporation
from July of 1992 until his retirement in April 1995. He was also a
Director of Amoco Corporation from 1989 to his retirement. He is a
member of the Board of Trustees of the Museum of Science and Industry
in Chicago.
Clyde M. Heiner, 62, Chief Operating Officer, Consonus, Inc., a
Questar affiliate (August 2000); Senior Vice President, Questar (May
1984 to June 2000); President and Chief Executive Officer, Questar
InfoComm (February 1993 to June 2000); Director, QMR (May 1984).
W. N. Jones, 74, Director, QMR (May 1989); Senior Director, Questar
(May 1998); Director, Questar (May 1981 to May 1998). Mr. Jones is
Chairman of the Board, Lite Touch Inc., and a Trustee of Intermountain
Health Care, Inc.
ITEM 6. EXECUTIVE COMPENSATION
Omitted.
ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Omitted.
ITEM 8. LEGAL PROCEEDINGS
Questar E&P, as well as other QMR affiliates and Questar, are among
the named defendants in a class action lawsuit commenced in 1995
involving royalty payments in Oklahoma state court for Texas County,
Oklahoma. In Bridenstine vs. Kaiser-Francis Oil Company, the
plaintiffs alleged various fraud and contract claims against all
defendants for a 17-year period. While this litigation does not
specify the amount of damages being claimed, estimates have at times
been in excess of $80 million, plus punitive damages. The
plaintiffs' primary claim alleges that a transportation fee charged
-28-
<PAGE>
against royalty payments was improper or excessive. The claims
involve wells connected to an intrastate pipeline system that Questar
Gas Management presently owns and operates. The suit also alleges
claims for mismeasurement of gas and failure to market the gas for the
"best available price." Kaiser-Francis and Questar E&P are the major
working interest owners and operators of a majority of the wells
connected to this pipeline system. QMR disputes plaintiffs' claims
and will continue to vigorously defend against such litigation. QMR
cannot predict the outcome of the lawsuit, which will be tried before
a jury beginning in February 2001 and which may result in a material
adverse judgment.
At year end, Questar E&P was a defendant in a case styled Greghol
Limited Partnership vs. Universal Resources Corporation, filed in
Oklahoma state court, which was originally asserted as a statewide
class action raising issues relative to calculation of royalties, and
whether such calculations should reflect deductions for certain
post-production costs. Relief sought by the plaintiff was
unspecified. The Court has sustained Questar E&P's motion to
de-certify the class. Questar E&P disputes these claims. In August
2000, plaintiff voluntarily dismissed the case without prejudice.
In United States ex rel. Grynberg v. Questar Corp., et al., each of
Questar Gas Management, Wexpro and Universal Resources Corporation
d/b/a Questar Energy Trading Company are named as defendants in a case
involving allegations of gas mismeasurement and of improper royalty
valuations. The plaintiff filed on behalf of the federal government
to recover underpaid royalties under the False Claims Acts, and the
Department of Justice declined to intervene. Relief sought by the
plaintiff is unspecified. This case and 75 substantially similar
cases filed by the plaintiff have been consolidated for discovery and
pre-trial rulings in Wyoming's federal district court. Motions to
dismiss have been filed. The QMR subsidiaries dispute these claims.
Questar Energy Trading and Questar Gas Management, two of the
Company's wholly owned subsidiaries, have been added as defendants in
a lawsuit filed by Jack Grynberg, an independent producer, pending in
a Utah state district court (Grynberg v. Questar Pipeline Company).
The lawsuit was originally filed against Questar Pipeline Company, an
affiliate of the Company in Questar's Regulated Services unit, in
September of 1999. It alleges that the Questar defendants mismeasured
gas volumes attributable to his working interest from a property in
southwestern Wyoming. The plaintiff cites mismeasurement to support
claims for breach of contract, negligent misrepresentation, fraud,
breach of fiduciary responsibilities and alleges damages of $27
million. The Questar defendants have filed a comprehensive motion to
dismiss the complaint on several grounds including expiration of the
applicable statute of limitations, no basis for independent tort
claims, and federal preemption.
In Quinque Operating Company v. Gas Pipelines, et al., each of Questar
Gas Management, Wexpro and Universal Resources Corporation (now known
as Questar E&P) is named as a defendant in a lawsuit involving
allegations of mismeasurement of natural gas resulting in underpayment
of royalties to private and state lessors. Relief sought by the
plaintiff is unspecified. Plaintiffs have asked that the case be
certified as a nationwide class action. The case was removed from
state to federal court and a motion to remand is pending. There are
over 220 defendants. The QMR subsidiaries dispute these claims.
Royalty class actions such as Quinque are being asserted in numerous
states against other companies in the oil and gas production and
marketing businesses in which QMR's subsidiaries participate.
Accordingly, QMR expects similar royalty class actions to be filed in
other states in which it has significant production and marketing
activities such as Wyoming and Colorado, although such actions have
not yet been filed and are not currently threatened.
There are various other legal proceedings against subsidiaries of QMR.
The Company regularly reviews potential liabilities related to legal
proceedings and records accruals after considering estimates of the
outcome of such matters and our experience in contesting, litigating,
and settling similar matters. While it is not currently possible to
predict or determine the outcomes of the Bridenstine case or various
other legal proceedings against QMR, it is the opinion of management
that the outcomes will not have a material adverse effect on the
Company's future results of operations, financial position or
liquidity.
Also see Note 7 of the Notes to Consolidated Financial Statements
under Item 13 of this Form 10.
-29-
<PAGE>
ITEM 9. MARKET PRICE OF AND DIVIDENDS OF THE REGISTRANT'S COMMON
EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Company is owned entirely by Questar and,
therefore, there is no trading of the Company's stock. Dividends of
$4.3 million, $16.6 million, $15.9 million, and $16.3 million were
declared and paid during the three months ended March 31, 2000, and
the years ended December 31, 1999, 1998 and 1997, respectively. See
Note 4 of the Notes to Consolidated Financial Statements under Item 13
of this Form 10 regarding restrictions as to dividend availability.
ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES
There have been no sales of unregistered securities by the Company.
ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED
The following description of the capital stock of the Company and
certain provisions of the Company's Amended Articles of Incorporation
and Bylaws is a summary and is qualified in its entirety by the
provisions of the Amended Articles of Incorporation and Bylaws, which
have been filed as exhibits to this Form 10.
The Company has authorized twenty-five million (25,000,000) shares of
Common Stock with a par value of $1.00 per share. All outstanding
shares of stock are held by Questar Corporation. No preferred stock
has been issued or authorized.
Each common shareholder of record is entitled to one vote, by person
or by proxy for each share of Common Stock held on every matter
properly submitted to the stockholders for a vote. Except as
otherwise provided by law or in the Amended Articles of Incorporation
or Bylaws, stockholder votes are decided by a majority vote of the
outstanding shares.
ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Reference is made to Section 16-10a-901 through 16-10a-909 of the Utah
Revised Business Corporation Act, which provides for indemnification
of directors and officers in certain circumstances.
The Bylaws provide that the Company may voluntarily indemnify any
individual made a party to a proceeding because he is or was a
director, officer, employee or agent of the Company against liability
incurred in the proceeding, but only if the Company has authorized the
payment in accordance with the applicable statutory provisions of the
Utah Revised Business Corporation Act (Sections 16-10a-902, 16-10a-904
and 16-10a-907) and a determination has been made in accordance with
the procedures set forth in such provision that such individual
conducted himself in good faith, that he reasonably believed his
conduct, in his official capacity with the Company, was in its best
interests and that his conduct, in all other cases, was at least not
opposed to the Company's best interests, and that he had no reasonable
cause to believe his conduct was unlawful in the case of any criminal
proceeding. The foregoing indemnification in connection with a
proceeding by or in the right of the Company is limited to reasonable
expenses incurred in connection with the proceeding, which expenses
may be advanced by the Company. The Company's Bylaws provide that the
Company may not voluntarily indemnify a director, officer, employee or
agent of the Company in connection with a proceeding by or in the
right of the Company in which such individual was adjudged liable to
the Company or in connection with any other proceeding charging
improper personal benefit to him, whether or not involving action in
his official capacity, in which he was adjudged liable on the basis
that personal benefit was improperly received by him.
The Bylaws provide further that the Company shall indemnify a
director, officer, employee or agent of the Company who was wholly
successful, on the merits or otherwise, in defense of any proceeding
to which he was a party because he is or was such a director, officer,
employee or agent, against reasonable expenses incurred by him in
connection with the proceeding.
-30-
<PAGE>
The Bylaws further provide that no director of the Company shall be
personally liable to the Company or its stockholders for monetary
damages for any action taken or any failure to take any action, as a
director, except liability for (a) the amount of a financial benefit
received by a director to which he is not entitled; (b) an intentional
infliction of harm on the Company or the shareholders; (c) for any
action that would result in liability of the director under the
applicable statutory provision concerning unlawful distributions; or
(d) an intentional violation of criminal law.
Questar, the Company's parent, maintains an insurance policy on behalf
of the officers and directors of the Company pursuant to which
(subject to the limits and limitations of such policy) the officers
and directors are insured against certain expenses in connection with
the defense of actions or proceedings, and certain liabilities which
might be imposed as a result of such actions or proceedings, to which
any of them is made a party by reason of being or having been a
director or officer.
ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements and Supplementary Data
Page
Financial Statements -
Report of Independent Auditors 32
Consolidated Statements of Income for the years ended December 31,
1999, 1998 and 1997 and for the three months ended March 31, 2000
(unaudited) and 1999 (unaudited) 33
Consolidated Balance Sheets at December 31, 1999 and 1998 and
March 31, 2000 (unaudited) 34
Consolidated Statements of Shareholder's Equity for the years ended
December 31, 1999, 1998 and 1997 and for the three months ended
March 31, 2000 (unaudited) 36
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998, and 1997 and for the three months ended
March 31, 2000 (unaudited) and 1999 (unaudited) 37
Notes to Consolidated Financial Statements 38
Supplementary Data -
Oil and Gas Producing Activities (Note 13 to Consolidated Financial
Statements) 52
-31-
<PAGE>
Report of Independent Auditors
Board of Directors
Questar Market Resources, Inc.
We have audited the accompanying consolidated balance sheets of
Questar Market Resources, Inc. and subsidiaries as of December 31,
1999, and 1998, and the related consolidated statements of income and
common shareholder's equity and cash flows for each of the three years
in the period ended December 31, 1999. 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 consolidated financial position
of Questar Market Resources, Inc. and subsidiaries at December 31,
1999, and 1998, and the consolidated results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
/s/ Ernst & Young LLP
Ernst & Young LLP
Salt Lake City, Utah
February 7, 2000
-32-
<PAGE>
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
For the Three Months For the Year
Ended March 31, Ended December 31,
2000 1999 1999 1998 1997
(Unaudited)
<S> <C> <C> <C> <C> <C>
REVENUES
From unaffiliated customers $119,471 $94,643 $418,603 $382,791 $451,233
From affiliates 22,290 21,203 79,708 75,481 72,407
TOTAL REVENUES 141,761 115,846 498,311 458,272 523,640
OPERATING EXPENSES
Natural gas and other
product purchases 63,893 56,392 239,201 230,462 291,851
Operating and maintenance 22,918 20,169 79,916 73,763 72,958
Depreciation and amortization 20,977 19,605 78,608 71,377 67,078
Write-down of full cost oil
and gas properties 31,000 6,000
Write-down of gas gathering
properties 3,000
Other taxes 7,314 5,128 21,516 24,988 25,569
Wexpro settlement agreement
- oil income sharing 984 209 2,292 1,053 2,347
TOTAL OPERATING EXPENSES 116,086 101,503 421,533 432,643 468,803
OPERATING INCOME 25,675 14,343 76,778 25,629 54,837
INTEREST AND OTHER INCOME 1,093 847 4,272 3,638 5,854
INCOME (LOSS) FROM UNCONSOLIDATED
AFFILIATES 999 (31) 763 (930) (288)
DEBT EXPENSE (5,370) (4,263) (17,363) (12,631) (10,882)
INCOME FROM CONTINUING
OPERATIONS BEFORE
INCOME TAXES 22,397 10,896 64,450 15,706 49,521
INCOME TAX EXPENSE (CREDIT) 7,348 2,643 18,584 (1,019) 10,410
INCOME FROM CONTINUING
OPERATIONS 15,049 8,253 45,866 16,725 39,111
DISCONTINUED OPERATIONS - QUESTAR
ENERGY SERVICES, NET OF INCOME
TAXES OF $347 IN 1998 AND
$631 IN 1997 (563) (1,021)
NET INCOME $15,049 $8,253 $45,866 $16,162 $38,090
</TABLE>
See accompanying notes to consolidated financial statements.
-33-
<PAGE>
<TABLE>
<CAPTION>
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
ASSETS
As of March 31, As of December 31,
2000 1999 1998
(Unaudited)
<S> <C> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 2,206 $ 1,894
Notes receivable from Questar $ 4,000 25,100
Accounts receivable, net of
allowance of $1,321 in 2000,
$1,350 in 1999, and $3,253 in 1998 71,097 64,364 61,833
Accounts receivable from affiliates 11,962 11,459 11,359
Inventories, at lower of average
cost or market -
Gas and oil storage 2,699 8,863 8,892
Materials and supplies 2,421 2,390 1,893
Prepaid expenses and deposits 5,806 4,452 4,369
TOTAL CURRENT ASSETS 96,191 95,528 115,340
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, on the basis
of full cost accounting -
Proved properties 1,009,167 943,349 918,237
Unproved properties,
not being amortized 87,138 69,777 62,487
Support equipment and facilities 16,370 13,408 14,878
Cost of service oil and gas
properties, on the basis of
successful efforts accounting 318,882 318,451 297,809
Gathering, processing and marketing 125,204 124,691 119,230
1,556,761 1,469,676 1,412,641
Less: Allowances for depreciation
and amortization 801,217 778,695 717,129
NET PROPERTY, PLANT AND EQUIPMENT 755,544 690,981 695,512
INVESTMENT IN UNCONSOLIDATED AFFILIATES 14,225 13,301 3,673
OTHER ASSETS - Note 3 52,374 48,081 628
$918,334 $847,891 $815,153
</TABLE>
-34-
<PAGE>
LIABILITIES AND SHAREHOLDER'S EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
As of March 31, As of December 31,
2000 1999 1998
(Unaudited)
<S> <C> <C> <C>
CURRENT LIABILITIES
Checks outstanding in excess
of cash balances $ 1,246
Notes payable to Questar $ 49,700 24,500 $121,800
Accounts payable and accrued expenses
Accounts and other payables 64,157 67,385 63,272
Accounts payable to affiliates 2,244 2,952 2,414
Federal income taxes 8,267 6,232 6,105
Other taxes 16,980 14,266 13,661
Accrued interest 2,344 1,443 1,044
TOTAL CURRENT LIABILITIES 143,692 118,024 208,296
INVESTMENT IN DISCONTINUED OPERATIONS -
Questar Energy Services 1,905
LONG-TERM DEBT 293,074 264,894 181,624
DEFERRED INCOME TAXES 66,080 59,936 52,113
OTHER LIABILITIES 13,051 14,674 11,577
MINORITY INTEREST 2,882 2,529
COMMITMENTS AND CONTINGENCIES - Note 7
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 4,309
Additional paid-in capital 116,027 116,027 116,027
Retained earnings 281,112 270,388 239,217
Other comprehensive income (loss) (1,893) (2,890) 85
399,555 387,834 359,638
$918,334 $847,891 $815,153
</TABLE>
See accompanying notes to consolidated financial statements.
-35-
<PAGE>
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDER'S EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
Additional Other
Common Paid-in Retained Comprehesive Comprehensive
Stock Capital Earnings Income Income
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1997 $4,309 $116,027 $217,190 ($181)
Net income 38,090 $38,090
Cash dividends (16,325)
Foreign currency translation
adjustment, net of income
taxes of $98 173 173
Balance at December 31, 1997 4,309 116,027 238,955 (8) $38,263
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
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 tax credit 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
Net income (unaudited) 15,049 15,049
Cash dividends (4,325)
Unrealized gain on securities
available for sale, net of income
taxes of $811 1,309 1,309
Foreign currency translation
adjustment net of income
taxes of $263 (312) (312)
Balance at March 31, 2000
(unaudited) $4,309 $116,027 $281,112 ($1,893) $16,046
</TABLE>
See accompanying notes to consolidated financial statements.
-36-
<PAGE>
QUESTAR MARKET RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
For the Three Months For the Year
Ended March 31, Ended December 31,
2000 1999 1999 1998 1997
(Unaudited)
<S> <C> <C> <C> <C> <C>
OPERATING ACTIVITIES
Net income $15,049 $ 8,253 $ 45,866 $16,162 $38,090
Depreciation and amortization 21,148 20,194 81,150 71,951 67,667
Deferred income taxes 357 (226) 9,381 (4,619) (2,428)
Write-down of full cost oil
and gas properties 31,000 6,000
Write-down of gas gathering
properties 3,000
(Income) loss from unconsolidated
affiliates, net of cash
distributions (924) 85 (66) 1,211 1,872
Gain from sale of securities (388)
Loss from discontinued operations 563 1,021
Changes in operating assets and
liabilities
Accounts receivable (3,734) 9,697 (2,631) 20,572 22,196
Inventories 6,133 7,288 (468) (4,996) (1,045)
Prepaid expenses and deposits (1,354) 547 (83) 555 (191)
Accounts payable and accrued
expenses (4,651) (13,323) 5,655 (7,002) (3,883)
Federal income taxes payable 2,036 2,385 127 2,399 3,620
Other assets (1,305) 95 (783) (628) 1,213
Other liabilities (1,623) 1,976 3,097 345 (197)
NET CASH PROVIDED FROM OPERATING
ACTIVITIES 31,132 36,971 140,857 127,513 136,935
INVESTING ACTIVITIES
Capital expenditures
Purchases of property, plant
and equipment (80,336) (13,301) (109,405) (252,671) (92,310)
Other investments (812) (24,864) (1,875)
(80,336) (14,113) (134,269) (254,546) (92,310)
Proceeds from disposition of
property, plant and equipment 309 1,324 38,624 7,857 11,018
Proceeds from sale of securities 1,214
NET CASH USED IN INVESTING
ACTIVITIES (80,027) (12,789) (94,426) (246,689) (81,292)
FINANCING ACTIVITIES
Change in notes receivable from
Questar 4,000 (10,600) 21,100 8,400 (17,200)
Change in notes payable to Questar 25,200 (10,400) (97,300) 77,500 (23,700)
Change in short-term debt (10,000)
Cash in escrow balance (583) (36,727)
Checks written in excess of cash
balances (1,246) 1,246 (2,505)
Issuance of long-term debt 33,402 3,640 275,000 64,343 63,547
Payment of long-term debt (5,000) (195,000) (14,283) (48,432)
Payment of dividends (4,325) (4,150) (16,600) (15,900) (16,325)
NET CASH PROVIDED FROM (USED IN
FINANCING ACTIVITIES 51,448 (21,510) (48,281) 120,060 (54,615)
Foreign currency translation
adjustment (347) (44) (4) (14)
CHANGE IN CASH AND CASH EQUIVALENTS 2,206 2,672 (1,894) 880 1,014
Beginning cash and cash equivalents 1,894 1,894 1,014
ENDING CASH AND CASH EQUIVALENTS $2,206 $4,566 $ - $1,894 $1,014
</TABLE>
See accompanying notes to consolidated financial statements.
-37-
<PAGE>
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"). 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 Company ("Questar
E&P"), formerly named Celsius Energy Company and Universal Resources
Corporation, conducts the exploration, development and production
activities. Wexpro Company ("Wexpro") operates and develops producing
properties on behalf of an affiliate, Questar Gas Company ("Questar
Gas"). Questar Gas Management Company ("Questar Gas Management")
conducts gas gathering and plant processing activities. Questar
Energy Trading Company ("Questar Energy Trading") performs wholesale
energy marketing activities and, through a 75% interest in Clear Creek
Storage Company, LLC, constructed and operates a gas storage facility.
All significant intercompany balances and transactions have been
eliminated in consolidation.
Investments in Unconsolidated Affiliates: The Company owns a 15%
interest in Canyon Creek Compression Co., and a 50% interest in Blacks
Fork Gas Processing Co. The Company uses the equity method to account
for investments in affiliates in which it does not have control and
generally, its investment in these affiliates equals the underlying
equity in net assets.
Interim Financial Data: The unaudited consolidated financial
statements as of March 31, 2000, and for the three-month periods ended
March 31, 2000 and 1999, and all related footnote information for
these periods have been prepared on the same basis as the audited
financial statements and, in the opinion of management, include all
adjustments, consisting of normal recurring adjustments, necessary for
a fair presentation of financial position, results of operations and
cash flows in accordance with accounting principles generally accepted
in the United States and pursuant to the rules and regulations of the
Securities and Exchange Commission.
Use of Estimates: The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the 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.
Wexpro settlement agreement-oil income sharing: Wexpro settlement
agreement-oil income sharing represents payments made to Questar Gas
for their 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 10).
Cash and Cash Equivalents: Cash equivalents consist principally of
repurchase agreements with original maturities of three months or
less.
Notes receivable from Questar: Notes receivable from Questar represent
interest bearing demand notes for excess cash balances loaned to
Questar until the funds are needed in the Company's operations or
until bank borrowings can be repaid at maturity. The funds are
centrally managed by Questar and earn an interest rate that is
identical to the interest rate paid for borrowings from Questar.
Property, Plant and Equipment: QMR uses the full cost accounting
method for the majority of its oil and gas exploration and development
activities. However, as ordered by the Utah Public Service
Commission, 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 10). Pursuant
to the settlement agreement, production from the gas properties
operated by Wexpro is delivered
-38-
<PAGE>
to Questar Gas at Wexpro's cost of providing this service. That cost
includes a return on Wexpro's investment. While oil produced from the
cost of service properties is sold at market prices, the 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.
Exclusive of field-level costs, the Company capitalized
$3,003,000, $2,603,000, and $1,590,000 of internal costs in 1999,
1998, and 1997, respectively. Costs associated with production
and general corporate activities are expensed in the period
incurred, as are interest costs. 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
present value of estimated future net revenues from proved oil
and gas reserves, based upon current economic and operating
conditions and estimated future development expenditures,
discounted at 10%, plus the cost of unproved properties not being
amortized, as adjusted for related income tax effects (the full
cost ceiling). If capitalized costs exceed the full cost
ceiling, the excess is expensed. The Company recorded
write-downs of oil and gas properties pursuant to the ceiling
limitation required by the full cost accounting method amounting
to $31 million in 1998 and $6 million in 1997.
Capitalized costs are amortized, on a country by country cost
center basis, by an equivalent unit of production method based
upon production and estimates of proved reserves quantities. 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 oil
and gas properties until the properties are evaluated.
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 $69.8 million of net unproved
property costs at December 31, 1999 excluded from the amortizable
base, $14.2 million, $27.7 million, and $7.8 million were
incurred in 1999, 1998, and 1997, 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 with
respect to 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
appurtenant 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 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.
-39-
<PAGE>
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 No. 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. The Company recorded a write-down of its
investment in gas gathering properties of $3 million in 1997
under the provisions of SFAS 121.
Depreciation and amortization -
Depreciation and amortization expense consists of the following
components (in thousands, except for rates):
<TABLE>
<CAPTION
For the Three
Months Ended For the Year
March 31, Ended December 31,
2000 1999 1999 1998 1997
(unaudited)
<S> <C> <C> <C> <C> <C>
Full cost oil and gas properties $16,076 $15,401 $61,057 $55,015 $51,175
Amortization rate, per unit
of production (Mcfe)
U.S. .80 .85 .81 .83 .81
Canada .81 .60 .65 1.04 1.17
Cost of service oil and gas
properties 3,537 3,024 12,665 11,379 10,213
Amortization rate, per unit
of production (Mcfe) .43 .40 .42 .39 .39
Gathering, processing and
marketing 1,364 1,180 4,886 4,983 5,690
Total $20,977 $19,605 $78,608 $71,377 $67,078
</TABLE>
Accumulated depreciation and amortization consists of the following
components:
<TABLE>
<CAPTION>
At March 31, At December 31,
2000 1999 1998
(unaudited)
<S> <C> <C> <C>
Full cost oil and gas properties $563,123 $544,491 $498,718
Cost of service oil and gas
properties 183,914 180,867 168,236
Gathering, processing and
marketing 54,180 53,337 50,175
Total $801,217 $778,695 $717,129
</TABLE>
-40-
<PAGE>
Capitalized Interest: The Company capitalizes interest costs, when
applicable, related to cost of service and 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. Capitalized interest aggregated
$357,000, $1,363,000, and $604,000 in 1999, 1998, and 1997,
respectively, and are included in Interest and Other Income in the
Consolidated Statements of Income.
Foreign Currency Translation: The Company conducts gas and oil
exploration and production activities 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.
Energy Price Risk Management: QMR enters into swaps, futures contracts
or option 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. There is a high
degree of correlation between such contracts and the physical
transactions. The timing of production and of the hedge contracts is
closely matched. Hedge prices are established in the areas of QMR's
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. Contracts no longer
qualifying for high correlation with the physical transactions would
be marked-to-market and recognized in current period income. Cash
flows from the hedge contracts are reported in the same category as
cash flows from the hedged assets. The Company does not enter into
hedging contracts for speculative purposes.
Interest Rate Risk Management: The Company uses variable rate debt as
part of its financing plans. These 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 region 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 entities that
may be affected differently by changing conditions. Management
believes that its credit-review procedures, loss reserves and customer
deposits have adequately provided for usual and customary
credit-related losses.
Income Taxes: The Company accounts for income tax expense on a
separate return basis. Pursuant to Internal Revenue Code Regulations,
the Company's operations are consolidated with those of Questar and
its subsidiaries for income tax purposes. The income tax arrangement
between QMR and Questar provides that the tax liability of the group
shall be allocated to the several members of the group on the basis of
the percentage of the total tax which the tax of such member if
computed on a separate return would bear to the total amount of the
taxes for all members of the group so computed. The Company also
receives payment for tax benefits used in the consolidated tax return
even if such benefits would not have been usable had the Company filed
a separate return.
Comprehensive Income: QMR reports comprehensive income on the
Consolidated 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. The balances in accumulated foreign currency translation
adjustments and unrealized losses on securities available for sale
amounted to $375,000 and $2,515,000, respectively, at December 31,
1999. The balance in accumulated foreign currency translation
adjustments at December 31, 1998, was $85,000. Income is realized
when the securities available for sale are sold. Income taxes
associated with realized gains from selling securities available for
sale were $146,000 in 1999.
New accounting standard: The Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standard ("SFAS")
No. 133, "Accounting for Derivative Instruments and Hedging
Activities" in June 1998.
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<PAGE>
The Statement establishes accounting and reporting standards requiring
that the fair value of all derivative instruments be recorded in the
balance sheet as either an asset or liability. The Statement requires
that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met wherein
gains and losses are to be reflected in other comprehensive income in
shareholder's equity until the hedged item is recognized.
Due to the issuance of SFAS No. 137, which deferred the effective date
of SFAS No. 133, the Company is required to adopt the statement for
fiscal years beginning after June 15, 2000. The Company has not
quantified the impact of adopting SFAS No. 133, but plans on adopting
the statement by January 1, 2001.
During 2000, the FASB issued SFAS No. 138, which amends the accounting
and reporting standards of SFAS No. 133 for certain derivative
instruments and certain hedging activities and should be adopted
concurrently with SFAS No. 133, according to its provisions and the
issuance of SFAS No. 137. The Company has not quantified the impact
SFAS No. 138 will have upon the adoption of SFAS No. 133.
Reclassifications: Certain reclassifications were made to the 1998
and 1997 financial statements to conform with the 1999 presentations.
Note 2 - Acquisitions
HSRTW, Inc.
A subsidiary of QMR acquired 100% of the common stock of HSRTW, Inc.,
a wholly owned subsidiary of HS Resources, Inc. for $155 million,
effective September 1, 1998. QMR obtained an estimated 150 Bcfe of
proved oil and gas reserves primarily in Oklahoma, Texas, Arkansas,
and Louisiana as a result of the transaction. The cash transaction
was accounted for under the purchase method of accounting for business
combinations.
The Company's consolidated statement of income for the year ended
December 31, 1998, includes only four months of operations from the
HSRTW acquisition. The following unaudited pro forma consolidated
results of operations assume the acquisition occurred on January 1 of
each year. The pro forma results do not necessarily represent results
which would have occurred if the acquisition had taken place on the
basis assumed above, nor are they indicative of the results of future
combined operations.
For the year ended December 31,
(In Thousands) 1998 1997
(Unaudited)
Total Revenuese $479,649 $573,959
Net Income $ 21,215 $ 45,846
The pro forma amounts reflect the combined results of the Company,
HSRTW, and the following purchase accounting adjustments for the
periods presented:
depreciation and amortization calculated on the basis of the
allocated purchase price and acquired proved reserves;
incremental interest expense on additional debt that would
have been incurred to finance the acquisition;
estimated general and administrative expenses based on
consolidated efficiencies; and
estimated income tax effects on the pro forma adjustments.
-42-
<PAGE>
Canor Energy Ltd.
On January 26, 2000, a subsidiary of QMR acquired 100% of the
outstanding shares of Canor from NI Canada ULC, a subsidiary of
Northwest Natural Gas Co., for cash of $US 61 million plus the
assumption of $5.4 million of short-term debt. The transaction was
accounted for as a purchase. Canor owns and/or operates more than 800
wells located in Alberta, British Columbia, and Saskatchewan provinces
of Canada. Canor's proven gas and oil reserves were estimated at 61.1
Bcfe. Assets purchased and liabilities assumed were as follows:
(In Thousands)
Cash $ 245
Other current assets 3,502
Property, plant and equipment 73,720
Other assets 282
Short-term debt (5,444)
Other current liabilities (4,356)
Deferred income taxes (4,976)
Other liabilities (1,989)
Total purchase price, including
acquisition costs $60,984
Note 3 - Other Assets
Other assets include the following:
<TABLE>
<CAPTION>
As of March 31, As of December 31,
2000 1999 1998
(In Thousands) (Unaudited)
<S> <C> <C> <C>
Cash held in escrow account (a) $37,310 $36,727
Securities available for sale (b) 12,522 10,402 $628
Other 2,542 952
Total other assets $52,374 $48,081 $628
_______________
</TABLE>
(a)Proceeds from the sale of nonstrategic oil and gas properties in
November and December of 1999, were placed in escrow with a
qualified intermediary in accordance with the statutory
requirements for a tax-free exchange under U.S. Internal Revenue
Code Section 1031.
(b)The value of securities available for sale approximate fair
value at the balance sheet date based on published share prices.
The Company records unrealized gains or losses, based on market
value net of income taxes, as a separate component of other
comprehensive income in shareholder's equity. Gains or losses
resulting from the sale of securities are included in the
determination of income.
Note 4 - Debt
QMR has a $300 million senior revolving credit facility agented by
Bank of America. Borrowing under this agreement amounted to $264.9
million at December 31, 1999 at a 6.54% interest rate. The agreement
was entered into April 1999 and replaced an unsecured short-term and
long-term line-of-credit arrangements with various banks. The loan is
-43-
<PAGE>
segmented into US and Canadian portions. The US portion of the loan
is a 5-year facility with $227 million available. The Canadian portion
amounts to $68 million and is a 6-year facility. The interest rate is
generally equal to LIBOR plus a small premium. Under the most
restrictive terms of the senior-revolving credit facility, QMR could
have paid a dividend of $57.6 million at December 31, 1999.
Maturities of long-term debt for the five years following December 31,
1999, are as follows:
(In Thousands)
2000 $ -
2001 2,995
2002 30,995
2003 2,995
2004 179,995
Questar makes loans to QMR under a short-term borrowing arrangement.
Short-term notes payable to Questar outstanding as of December 31,
1999 amounted to $24.5 million with an average interest rate of 6.61%
and $121.8 million as of December 31, 1998 with an interest rate of
5.71%.
Cash paid for interest was $16,964,000 in 1999, $13,229,000 in 1998
and $11,557,000 in 1997.
Note 5 - Financial Instruments
The carrying amounts and estimated fair values of the Company's
financial instruments were as follows:
<TABLE>
<CAPTION>
December 31, 1999 December 31, 1998
Carrying Estimated Fair Carrying Estimated
Value Value Value Fair Value
(In Thousands)
<S> <C> <C> <C> <C>
Financial assets
Cash and cash equivalents $1,894 $1,894
Notes receivable from Questar $4,000 $4,000 25,100 25,100
Financial liabilities
Short-term loans 25,746 25,746 121,800 121,800
Long-term debt 264,894 264,894 181,624 181,624
Gas and oil price hedging
contracts (6,200) 6,000
</TABLE>
The Company used the following methods and assumptions in estimating
fair values: (1) Cash and cash equivalents, notes receivable from
Questar 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, 1999 was $18.83
per bbl 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 between $17.22 and $17.67 per bbl. The average
price of the gas contracts at December 31, 1999 was $2.22 per Mcf
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 QMR-owned production and gas
marketing transactions. Transportation and heat value adjustments on
the hedges of Company-owned gas as of December 31, 1999 would result
in an average price of between $2.15 and $2.23 per Mcf, net back to
the well.
-44-
<PAGE>
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 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 oil or gas production).
Energy Price Risk Management: The Company held open hedge contracts
covering the price exposure for about 72.1 million Dth of gas and 2.4
million barrels of oil at December 31, 1999 and 45.3 million Dth of
gas and 464,000 barrels of oil at December 31, 1998. The hedging
contracts are primarily for gas and oil marketing activities, but also
include QMR-owned production. The contracts at December 31, 1999 had
terms extending through December 2001 with about 65% of those
contracts expiring by the end of 2000. 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 Management: The Company's primary areas are the Rocky
Mountain and Mid-Continent regions 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, and collection procedures have adequately
protected against unusual credit related losses.
Interest Rate Risk Management: The Company had $264.9 million of
variable rate long-term debt outstanding at December 31, 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. The net assets of the foreign operation were negative
at December 31, 1999. Long-term debt owned by the foreign operation,
amounting to $59.9 million (U.S.), is expected to be repaid from the
future foreign operations.
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.
Note 6 - Income Taxes
The components of income taxes expense (benefit) for years ended
December 31 were as follows:
<TABLE>
<CAPTION>
1999 1998 1997
(In Thousands)
<S> <C> <C> <C>
Federal
Current $11,411 $4,263 $14,574
Deferred 4,826 (86) (1,218)
State
Current 1,568 228 1,350
Deferred 620 1,007 (291)
Foreign 159 (6,431) (4,005)
Income taxes $18,584 ($1,019) $10,410
</TABLE>
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:
-45-
<PAGE>
<TABLE>
<CAPTION>
1999 1998 1997
(In Thousands)
<S> <C> <C> <C>
Income from continuing operations
before income taxes $64,450 $15,706 $49,521
Federal income taxes at statutory rate $22,558 $ 5,497 $17,332
State income taxes, net of federal
income tax benefit 1,422 803 745
Nonconventional fuel credits (5,282) (5,736) (6,633)
Foreign income taxes 48 (1,771) (630)
Other (162) 188 (404)
Income taxes $18,584 ($1,019) $10,410
Effective income tax rate 28.8% - 21.0%
</TABLE>
Significant components of the Company's deferred tax liabilities and
assets at December 31 were as follows:
<TABLE>
<CAPTION>
1999 1998
(In Thousands)
<S> <C> <C>
Deferred tax liabilities
Property, plant and equipment $74,333 $64,674
Other 509 205
74,842 64,879
Deferred tax assets
Alternative minimum tax and
nonconventional fuel credit
carry-forwards 2,468 6,535
Reserves, compensation plans and other 12,438 6,231
14,906 12,766
Net deferred tax liabilities $59,936 $52,113
</TABLE>
The Company paid $7,183,000 in 1999 and $9,029,000 in 1997 for income
taxes. Cash received for income taxes amounted to $1,856,000 in 1998.
Note 7 - Litigation and Commitments
Questar E&P, as well as QMR and Questar, are among the named
defendants in a class action lawsuit involving royalty payments in
Oklahoma state court. In Bridenstine vs. Kaiser-Francis Oil Company,
the plaintiffs have alleged various fraud and contract claims against
all defendants for a 17-year period. While this litigation does not
specify the amount of damages being claimed, estimates have at times
been in excess of $80 million, plus punitive damages. Management
cannot predict the outcome of the lawsuit, which will be tried before
a jury beginning February of 2001, and which may result in a material
adverse judgment. The plaintiffs' primary claim alleges that a
transportation fee charged against royalty payments was improper or
excessive. The claims involve wells connected to an intrastate
pipeline system that Questar Gas Management presently owns and
operates. Kaiser-Francis and Questar E&P are the major working
interest owners and operators of a majority of the wells connected to
this pipeline system. Questar E&P disputes plaintiffs' claims and
will continue to vigorously defend against such litigation.
-46-
<PAGE>
The Company regularly reviews potential liabilities related to legal
proceedings and records appropriate accruals after considering
estimates of the outcome of such matters and our experience in
contesting, litigating, and settling similar matters. While it is not
currently possible to predict or determine the outcome of the
Bridenstine case or various other legal proceedings against QMR, it is
the opinion of management that the outcomes will not have a material
adverse effect on the Company's future results of operations,
financial position or liquidity.
Questar Energy Trading has contracted for firm-transportation services
with various pipelines to transport 76.2 MDths per day of gas. The
contracts extend for the next seven 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. Also, Questar
Energy Trading has reserved firm-storage capacity of 1,065 MDths 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 five years
following December 31, 1999, are as follows:
(In Thousands)
2000 $1,980
2001 1,918
2002 1,371
2003 507
2004 43
Total minimum future rental payments have not been reduced for
sublease rental receipts of $96,000, $96,000, and $24,000, which are
expected to be received in the years ended December 31, 2000, 2001,
and 2002, respectively.
Total rental expense amounted to $1,804,000, $1,397,000, and
$1,112,000 in 1999, 1998, and 1997, respectively. Sublease rental
receipts were $94,000 in 1999.
Note 8 - Employment Benefits
Pension Plan: Substantially all of QMR's employees are covered by
Questar's defined benefit pension plan. Benefits are generally based
on years of service and the employee's 72-pay period interval of
highest earnings during the ten years preceding retirement. It is the
Company's policy 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
$887,000 in 1999, $761,000 in 1998 and $1,345,000 in 1997. Included
in pension cost for 1997 is $419,000 of expense associated with an
early retirement package offered to a limited number of the Company's
employees.
QMR's 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, 1999, Questar's fair value of plan assets exceeded the
accumulated benefit obligation.
Postretirement Benefits Other Than Pensions: QMR 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 the transition obligation over a 20-year period, which
began in 1992. Costs of postretirement benefits other than pensions
were $1,158,000 in 1999 and $1,018,000 in 1998 and $1,083,000 in 1997.
-47-
<PAGE>
QMR's 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: The Company recognizes the net present value
of the liability for postemployment benefits, such as long-term
disability benefits and health-care and life-insurance costs, when
employees become eligible for such benefits. Postemployment benefits
are paid to former employees after employment has been terminated but
before retirement benefits are paid. The Company accrues both current
and future costs. The liability is remeasured each year and the
change is recorded in income. Postemployment benefits accumulate for
salary continuation, health-care and life-insurance costs. Benefits
are paid from the Company's general funds. The Company's
postemployment benefit liability at December 31, 1999 was $381,000 and
in 1998 was $376,000 based on discount rates of 7.75% and 6.75%,
respectively.
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 makes matching
contributions to the EIP of 80% of the first 6% of salary contributed
by employees 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 $895,000 in 1999, $811,000 in 1998 and
$747,000 in 1997.
Note 9 - Related Party Transactions
QMR receives a significant portion of its revenues from services
provided to Questar Gas. The Company received $79,324,000 in 1999,
$75,171,000 in 1998 and $72,138,000 in 1997 for operating cost of
service oil and gas properties, gathering gas and supplying a portion
of gas for resale, among other services provided to Questar Gas.
Operation of cost of service oil and gas properties is described in
Wexpro Settlement Agreement (Note 10). The Company also received
revenues from other affiliated companies totaling $384,000 in 1999,
$310,000 in 1998 and $269,000 in 1997.
Questar performs certain administrative functions for QMR. The
Company was charged for its allocated portion of these services which
totaled $4,469,000 in 1999, $3,970,000 in 1998 and $5,311,000 in 1997.
These costs are included in operating and maintenance expenses and are
allocated based on each affiliate's proportional share of revenues;
net of product costs; property, plant and equipment; and payroll.
Management believes that the allocation method is reasonable and that
expenses would be substantially the same if incurred on a standalone
basis.
QMR's subsidiaries contracted for transportation and storage services
with Questar Pipeline and paid $3,378,000 in 1999, $3,968,000 in 1998
and $4,011,000 in 1997 for those services.
Questar InfoComm Inc is an affiliated company that provides some data
processing and communication services to QMR. The Company paid
Questar InfoComm $2,276,000 in 1999, $2,273,000 in 1998 and $2,391,000
in 1997.
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
annual lease payment, which began October of 1997, is $863,000.
The Company received interest income from affiliated companies of
$681,000 in 1999, $1,908,000 in 1998 and $2,370,000 in 1997. QMR
incurred debt expense to affiliated companies of $3,350,000 in 1999,
$3,331,000 in 1998 and $2,661,000 in 1997.
Note 10 - Wexpro Settlement Agreement
Wexpro's operations are subject to the terms of the Wexpro settlement
agreement. The agreement was effective August 1, 1981, and sets forth
the rights of Questar Gas' utility operations to share in the results
of Wexpro's operations. 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:
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<PAGE>
a. Wexpro continues to hold and operate all oil-producing
properties (productive oil reservoirs) previously transferred
from Questar Gas' 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 13.7%. 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
reservoirs 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
18.7%. 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
reservoirs 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
rate of return allowed Wexpro is approximately 21.7%.
e. Wexpro operates productive gas reservoir 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
13.7%.
Note 11 - Discontinued Operations - Transfer of Questar Energy
Services
QMR transferred all of its investment in Questar Energy Services, Inc.
("Questar Energy Services"), a wholly-owned subsidiary to Questar
Regulated Services Company ("Questar Regulated Services"), an
affiliate, effective January 1, 1999.
Questar Regulated Services, a wholly-owned subsidiary of Questar, is a
sub-holding company that holds the investment of Questar Gas, a retail
natural gas distributor. The transfer was in the form of a dividend
of 100% of the shares of Questar Energy Services at book value. No
gain or loss was generated as a result of the transfer. Questar
Energy Services provides energy management equipment, installation,
and service contracts for commercial and industrial clients and home
security systems, service contracts, and equipment financing to
residential customers and markets its services and products to many of
the same customers served by Questar Gas.
Summarized information relating to discontinued operations are as
follows:
For the Year Ended December 31,
1998 1997
(In thousands)
Revenues $2,355 $595
Operating (loss) (1,180) (1,773)
Net (loss) (563) (1,021)
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<PAGE>
At December 31,
1998 1997
(In thousands)
Total assets $7,230 $4,326
Total liabilities 9,135 5,668
Common equity (deficit) (1,905) (1,342)
Note 12 - 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.
Operating Segment Information
<TABLE>
<CAPTION>
For the Three Months For the Year
Ended March 31, Ended December 31,
2000 1999 1999 1998 1997
(Unaudited)
(In Thousands)
<S> <C> <C> <C> <C> <C>
Revenues from Unaffiliated Customers
Exploration and production $49,509 $36,200 $162,475 $135,509 $135,060
Cost of service 3,844 2,124 8,844 10,025 14,474
Gathering, processing, and marketing 66,118 56,319 247,284 237,257 301,699
$119,471 $94,643 $418,603 $382,791 $451,233
Revenues from Affiliated Companies
Cost of service $17,130 $15,094 $62,335 $58,581 $50,020
Gathering, processing, and marketing 5,160 6,109 17,373 16,900 22,387
$22,290 $21,203 $79,708 $75,481 $72,407
Depreciation and Amortization Expense
Exploration and production $16,076 $15,401 $61,057 $55,015 $51,175
Cost of service 3,537 3,024 12,665 11,379 10,213
Gathering, processing, and marketing 1,364 1,180 4,886 4,983 5,690
$20,977 $19,605 $78,608 $71,377 $67,078
Operating Income (Loss)
Exploration and production (1) $15,805 $4,975 $37,406 ($6,063) $27,555
Cost of service 9,031 7,794 32,948 28,218 24,988
Gathering, processing, and marketing (2) 839 1,574 6,424 3,474 2,294
$25,675 $14,343 $76,778 $25,629 $54,837
</TABLE>
-50-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
Income (Loss) from Continuing Operations
Exploration and production $8,396 $2,372 $20,808 ($3,257) $22,281
Cost of service 5,787 5,084 20,880 18,653 16,983
Gathering, processing, and marketing 866 797 4,178 1,329 (153)
$15,049 $8,253 $45,866 $16,725 $39,111
Fixed Assets - Net
Exploration and production $549,552 $492,815 $482,043 $496,884 $373,070
Cost of service 134,968 128,328 137,584 129,573 113,228
Gathering, processing, and marketing 71,024 66,896 71,354 69,055 68,878
$755,544 $688,039 $690,981 $695,512 $555,176
</TABLE>
Geographic Information
<TABLE>
<CAPTION>
For the Three Months For the Year
Ended March 31, Ended December 31,
2000 1999 1999 1998 1997
(In Thousands) (Unaudited)
<S> <C> <C> <C> <C> <C>
Revenues
United States $134,788 $113,362 $485,995 $447,798 $514,827
Canada 6,973 2,484 12,316 10,474 8,813
$141,761 $115,846 $498,311 $458,272 $523,640
Fixed Assets-Net
United States $648,922 $653,791 $654,961 $662,260 $511,547
Canada 106,622 34,248 36,020 33,252 43,629
$755,544 $688,039 $690,981 $695,512 $555,176
</TABLE>
______________
(1)The exploration and production segment impaired full cost oil
and gas properties by $31 million in 1998 and $6 million in
1997. The entire 1997 write-down was applicable to Canadian
operations, while $12 million of the 1998 write-down was
applicable to Canadian operations.
(2)The gathering, processing, and marketing segment recorded a $3
million write-down of its gas gathering assets under the
provision of SFAS 121 in 1997.
-51-
<PAGE>
Note 13 - Supplemental Oil and Gas Information (Unaudited)
QMR uses the full cost accounting method for the majority of its oil
and gas exploration and development activities. However, as ordered
by the Utah Public Service Commission, 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 10).
Oil and Gas Exploration and Development Activities: The following
information is provided with respect to QMR'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:
<TABLE>
<CAPTION>
December 31, 1999
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
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
December 31, 1998
United States Canada Total
(In Thousands)
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
</TABLE>
-52-
<PAGE>
<TABLE>
<CAPTION>
December 31, 1997
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
Proved properties $702,427 $41,994 $744,421
Unproved properties 19,200 13,390 32,590
Support equipment and facilities 12,556 888 13,444
734,183 56,272 790,455
Accumulated depreciation and amortization 404,742 12,643 417,385
$329,441 $43,629 $373,070
</TABLE>
Unproved Properties -
Unproved properties are excluded from amortization until evaluated. A
summary of costs excluded from amortization at December 31, 1999, and
the period in which these costs were incurred are listed below by cost
center:
<TABLE>
<CAPTION>
Year Costs Incurred
Total 1999 1998 1997 1996 and Prior
(In Thousands)
<S> <C> <C> <C> <C> <C>
United States
Acquisition $45,351 $11,447 $24,203 $1,165 $ 8,536
Exploration 12,897 2,302 2,542 2,078 5,975
58,248 13,749 26,745 3,243 14,511
Canada
Acquisition 10,111 281 585 4,327 4,918
Exploration 1,418 145 414 198 661
11,529 426 999 4,525 5,579
$69,777 $14,175 $27,744 $7,768 $20,090
</TABLE>
Costs Incurred -
The following costs were incurred with respect to oil and gas
exploration and development activities:
-53-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1999
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
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
Year Ended December 31, 1998
United States Canada Total
(In Thousands)
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
Year Ended December 31, 1997
United States Canada Total
(In Thousands)
Property acquisition
Unproved $4,057 $203 $4,260
Proved 2,155 2,155
Exploration 9,975 1,198 11,173
Development 28,511 4,437 32,948
$44,698 $5,838 $50,536
</TABLE>
Results of Operations -
Following are the results of operations of QMR's 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 pursuant to the ceiling limitation in 1998 and
1997.
-54-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1999
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
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
United States Canada Total
(In Thousands)
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 expenses 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
-55-
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1997
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
Revenues $126,247 $ 8,813 $135,060
Production expenses 36,922 2,424 39,346
Depreciation and amortization 45,801 5,374 51,175
Write-down of oil and gas properties 6,000 6,000
Total expenses 82,723 13,798 96,521
Revenues less expenses 43,524 (4,985) 38,539
Income taxes - Note A 9,330 (3,025) 6,305
Results of operations before corporate
overhead and interest expenses $34,194 ($1,960) $32,234
</TABLE>
Note A - Income tax expense has been reduced by nonconventional fuel
tax credits of $5,282,000 in 1999, $5,736,000 in 1998, and $6,633,000
in 1997.
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, Incorporated,
independent reservoir engineers. Estimated Canadian reserves were
prepared by Gilbert Laustsen Jung 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.
<TABLE>
<CAPTION>
Natural Gas Oil
United States Canada Total United States Canada Total
(MMcf) (MBbls)
Proved Reserves
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997 359,542 24,475 384,017 16,129 2,127 18,256
Revisions of estimates 11,177 (4,635) 6,542 (1,929) (316) (2,245)
Extensions and discoveries 24,306 4,366 28,672 669 898 1,567
Purchase of reserves in place 8,166 8,166 351 351
Sale of reserves in place (1,292) (1,292) (450) (3) (453)
Production (44,370) (3,072) (47,442) (2,106) (271) (2,377)
</TABLE>
-56-
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C)
Balance at December 31, 1997 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
Proved Developed Reserves
Balance at January 1, 1997 299,189 14,683 313,872 14,158 1,880 16,038
Balance at December 31, 1997 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
</TABLE>
Standardized Measure of Future Net Cash Flows Relating to Proved
Reserves -
Future net cash flows were calculated at December 31 using year-end
prices and known contract-price changes. Year-end production costs,
development costs and appropriate statutory income tax rates, with
consideration of any 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.
<TABLE>
<CAPTION>
Year Ended December 31, 1999
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
Future cash inflows $1,327,070 $107,227 $1,434,297
Future production and development
costs (459,625) (31,426) (491,051)
Future income tax expenses (181,644) (10,773) (192,417)
Future net cash flows 685,801 65,028 750,829
10% annual discount for estimated timing
of net cash flows (283,030) (23,365) (306,395)
Standardized measure of discounted future
net cash flows $402,771 $41,663 $444,434
</TABLE>
-57-
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31, 1998
United States Canada Total
(In Thousands)
<S> <C> <C> <C>
Future cash inflows $988,365 $66,873 $1,055,238
Future production and development costs (365,493) (22,784) (388,277)
Future income tax expenses (76,935) (76,935)
Future net cash flows 545,937 44,089 590,026
10% annual discount for estimated timing
of net cash flows (216,505) (14,809) (231,314)
Standardized measure of discounted future
net cash flows $329,432 $29,280 $358,712
Year Ended December 31, 1997
United States Canada Total
(In Thousands)
Future cash inflows $883,723 $68,550 $952,273
Future production and development costs (331,750) (25,066) (356,816)
Future income tax expenses (87,948) (87,948)
Future net cash flows 464,025 43,484 507,509
10% annual discount for estimated timing
of net cash flows (189,326) (14,885) (204,211)
Standardized measure of discounted future
net cash flows $274,699 $28,599 $303,298
The principal sources of change in the standardized measure of
discounted future net cash flows were:
Year Ended December 31,
1999 1998 1997
(In Thousands)
Beginning balance $358,712 $303,298 $395,372
Sales of oil and gas produced, net of
production costs (116,846) (93,717) (95,714)
Net changes in prices and production
costs 163,239 (51,568) (132,738)
Extensions and discoveries, less related
costs 78,611 24,430 28,964
Revisions of quantity estimates 28,311 (14,583) (5,529)
Purchase of reserves in place 3,764 129,867 2,155
Sale of reserves in place (33,043) (540) (3,606)
Accretion of discount 35,871 30,330 39,538
Net change in income taxes (62,263) 10,783 69,691
Change in production rate (12,627) 7,543 8,077
Other 705 12,869 (2,912)
Net change 85,722 55,414 (92,074)
Ending balance $444,434 $358,712 $303,298
</TABLE>
-58-
<PAGE>
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 as 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 and the
related amounts of accumulated depreciation and amortization follow:
<TABLE>
<CAPTION>
December 31,
1999 1998 1997
(In Thousands)
<S> <C> <C> <C>
Proved properties $318,451 $297,809 $270,073
Accumulated depreciation and amortization 180,867 168,236 156,845
$137,584 $129,573 $113,228
</TABLE>
Costs Incurred -
Costs incurred by Wexpro for cost of service oil and gas producing
activities were $21,273,000 in 1999, $26,956,000 in 1998, and
$26,837,000 in 1997.
Results of Operations -
Following are the results of operations of QMR's cost of service
activities before corporate overhead and interest expenses.
<TABLE>
<CAPTION>
Year Ended December 31,
1999 1998 1997
(In Thousands)
<S> <C> <C> <C>
Revenues
From unaffiliated companies $ 8,844 $10,025 $14,474
From affiliates - Note A 62,335 58,581 50,020
Total revenues 71,179 68,606 64,494
Production expenses 18,548 22,439 22,280
Depreciation and amortization 12,665 11,379 10,213
Total expenses 31,213 33,818 32,493
Revenues less expenses 39,966 34,788 32,001
Income taxes 14,602 12,441 11,334
Results of operations before corporate
overhead and interest expenses $25,364 $22,347 $20,667
</TABLE>
Note A - Represents revenues received from Questar Gas pursuant to
Wexpro settlement agreement.
-59-
<PAGE>
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.
<TABLE>
<CAPTION>
Natural Gas Oil
(MMcf) (MBbls)
<S> <C> <C>
Proved Developed Reserves
Balance at January 1, 1997 359,907 3,092
Revisions of estimates 7,240 123
Extensions and discoveries 7,486 419
Production (37,454) (585)
Balance at December 31, 1997 337,179 3,049
Revisions of estimates 15,017 (46)
Extensions and discoveries 25,077 333
Production (37,138) (613)
Balance at December 31, 1998 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
</TABLE>
ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not Applicable
ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS
(a)Reference is made to the Index to Consolidated Financial
Statements and Supplementary Data appearing at Item 13.
Financial Statements and Supplementary Data of this Form.
(b)The following is an Index of Exhibits required by Item 601
of Regulation S-K filed with the Securities and Exchange
Commission as part of this Form:
Exhibit
Number Description
3.1.* Articles of Incorporation dated April 27, 1988 for Utah
Entrada Industries, Inc.
3.2.* Articles of Merger, dated May 20, 1988, of Entrada
Industries, Inc., a Delaware corporation and Utah
Entrada Industries, Inc, a Utah corporation.
3.3.* Articles of Amendment dated August 31, 1998, changing
the name of Entrada Industries, Inc. to Questar Market
Resources, Inc.
-60-
<PAGE>
3.4.* Bylaws (as amended effective February 8, 2000).
4.1.1 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, and the Fifth Amendment
dated October 6, 2000.
4.2. Long-term debt instruments with principal amounts not
exceeding 10% of QMR's total consolidated assets are not
filed as exhibits to this Report. QMR will furnish a
copy of those agreements to the SEC upon its 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.)
10.2.2 Questar Market Resources, Inc. Annual Management
Incentive Plan, as amended and restated effective
October 26, 2000.
10.3.**2 Questar Corporation Executive Incentive Retirement
Plan, as amended and restated effective May 19, 1998.
(Exhibit No. 10.2. to Form 10-Q Report for Quarter Ended
June 30, 1998, filed by Questar Corporation.)
10.4.2 Questar Corporation Long-Term Stock Incentive Plan, as
amended and restated effective October 26, 2000.
10.5.**2 Questar Corporation Executive Severance Compensation
Plan, as amended and restated effective May 19, 1998.
(Exhibit No. 10.3. to Form 10-Q Report for Quarter Ended
June 30, 1998, filed by Questar Corporation.)
10.6.2 Questar Market Resources, Inc. Deferred Compensation
Plan for Directors, as amended and restated effective
October 26, 2000.
10.7.**2 Questar Corporation Supplemental Executive Retirement
Plan, as amended and restated effective June 1, 1998.
(Exhibit No. 10.6. to Form 10-Q Report for Quarter Ended
June 30, 1998, filed by Questar Corporation.)
10.8.**2 Questar Corporation Stock Option Plan for Directors,
as amended and restated effective October 29, 1998.
(Exhibit No. 10.10. to Form 10-Q Report for Quarter
Ended September 30, 1998, filed by Questar Corporation.)
10.9.**2 Form of Individual Indemnification Agreement dated
February 9, 1993 between Questar Corporation and
directors, including directors of Questar Market
Resources, Inc. (Exhibit No. 10.11. to Form 10-K Annual
Report for 1992 filed by Questar Corporation.)
10.10.**2 Questar Corporation Deferred Share Plan, as amended
and restated effective May 19, 1998. (Exhibit No. 10.7.
to Form 10-Q Report for Quarter Ended June 30, 1998,
filed by Questar Corporation.)
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<PAGE>
10.11.**2 Questar Corporation Deferred Compensation Plan, as
amended and restated effective May 19, 1998. (Exhibit
No. 10.10. to Form 10-Q Report for Quarter Ended June
30, 1998, filed by Questar Corporation.)
10.12.**2 Questar Corporation Directors' Stock Plan as approved
May 21, 1996. (Exhibit No. 10.15. to Form 10-Q Report
for Quarter ended June 30, 1996, filed by Questar
Corporation.)
10.13.**2 Questar Corporation Deferred Share Make-Up Plan.
(Exhibit No. 10.8. to Form 10-Q Report for Quarter Ended
June 30, 1998, filed by Questar Corporation.)
10.14.**2 Questar Corporation Special Situation Retirement
Plan. (Exhibit No. 10.10. to Form 10-Q Report for
Quarter Ended June 30, 1998, filed by Questar
Corporation.)
12. Ratio of Earnings to Fixed Charges.
27. Financial Data Schedule.
________________________
* Filed previously.
** Exhibits so marked have been filed with the Securities and
Exchange Commission as part of the indicated filing and are
incorporated herein by reference.
1 Only Annex I and Schedule I to the U.S. Credit Agreement, the
Fourth Amendment, and the Fifth Amendment are included. Other
items filed previously.
2 Exhibit so marked is a management contract or compensation plan
or arrangement.
SIGNATURES
Pursuant to the requirements of Section 12 of the Securities Exchange
Act of 1934, the registrant has duly caused this registration
statement to be signed on its behalf by the undersigned, thereunto
duly authorized.
QUESTAR MARKET RESOURCES, INC.
BY: /s/ G. L. Nordloh
G. L. NORDLOH
PRESIDENT AND CEO
Date: November 9, 2000
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<PAGE>
EXHIBIT INDEX
Exhibit
Number Description
3.1.* Articles of Incorporation dated April 27, 1988 for Utah
Entrada Industries, Inc.
3.2.* Articles of Merger, dated May 20, 1988, of Entrada Industries,
Inc., a Delaware corporation and Utah Entrada Industries, Inc,
a Utah corporation.
3.3.* Articles of Amendment dated August 31, 1998, changing the name
of Entrada Industries, Inc. to Questar Market Resources, Inc.
3.4.* Bylaws (as amended effective February 8, 2000).
4.1.1 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, and the Fifth Amendment dated October 6, 2000.
4.2. Long-term debt instruments with principal amounts not
exceeding 10% of QMR's total consolidated assets are not filed
as exhibits to this Report. QMR will furnish a copy of those
agreements to the SEC upon its 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.)
10.2.2 Questar Market Resources, Inc. Annual Management Incentive
Plan, as amended and restated effective October 26, 2000.
10.3.**2 Questar Corporation Executive Incentive Retirement Plan, as
amended and restated effective May 19, 1998. (Exhibit No.
10.2. to Form 10-Q Report for Quarter Ended June 30, 1998,
filed by Questar Corporation.)
10.4.2 Questar Corporation Long-Term Stock Incentive Plan, as amended
and restated effective October 26, 2000.
10.5.**2 Questar Corporation Executive Severance Compensation Plan, as
amended and restated effective May 19, 1998. (Exhibit No.
10.3. to Form 10-Q Report for Quarter Ended June 30, 1998,
filed by Questar Corporation.)
10.6.2 Questar Market Resources, Inc. Deferred Compensation Plan for
Directors, as amended and restated effective October 26, 2000.
10.7.**2 Questar Corporation Supplemental Executive Retirement Plan, as
amended and restated effective June 1, 1998. (Exhibit No.
10.6. to Form 10-Q Report for Quarter Ended June 30, 1998,
filed by Questar Corporation.)
10.8.**2 Questar Corporation Stock Option Plan for Directors, as
amended and restated effective October 29, 1998. (Exhibit No.
10.10. to Form 10-Q Report for Quarter Ended September 30,
1998, filed by Questar Corporation.)
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<PAGE>
10.9.**2 Form of Individual Indemnification Agreement dated
February 9, 1993 between Questar Corporation and directors,
including directors of Questar Market Resources, Inc.
(Exhibit No. 10.11. to Form 10-K Annual Report for 1992 filed
by Questar Corporation.)
10.10.**2 Questar Corporation Deferred Share Plan, as amended and
restated effective May 19, 1998. (Exhibit No. 10.7. to Form
10-Q Report for Quarter Ended June 30, 1998, filed by Questar
Corporation.)
10.11.**2 Questar Corporation Deferred Compensation Plan, as amended
and restated effective May 19, 1998. (Exhibit No. 10.10. to
Form 10-Q Report for Quarter Ended June 30, 1998, filed by
Questar Corporation.)
10.12.**2 Questar Corporation Directors' Stock Plan as approved May 21,
1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter
ended June 30, 1996, filed by Questar Corporation.)
10.13.**2 Questar Corporation Deferred Share Make-Up Plan. (Exhibit
No. 10.8. to Form 10-Q Report for Quarter Ended June 30, 1998,
filed by Questar Corporation.)
10.14.**2 Questar Corporation Special Situation Retirement Plan.
(Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June
30, 1998, filed by Questar Corporation.)
12. Ratio of Earnings to Fixed Charges.
27. Financial Data Schedule.
________________________
* Filed previously.
** Exhibits so marked have been filed with the Securities and
Exchange Commission as part of the indicated filing and are
incorporated herein by reference.
1 Only Annex I and Schedule I to the U.S. Credit Agreement, the
Fourth Amendment, and the Fifth Amendment are included. Other
items filed previously.
2 Exhibit so marked is a management contract or compensation
plan or arrangement.
-64-
<PAGE>
