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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
Amendment No. One
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _____ TO _____.
Commission File No. 1-8796
QUESTAR CORPORATION
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(Exact name of registrant as specified in its charter)
State of Utah 87-0407509
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
180 East 100 South, P.O. Box 45433, Salt Lake City, Utah 84145-0433
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(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (801) 324-5000
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, Without Par Value, with New York Stock Exchange
Common Stock Purchase Rights
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein and will not be contained, to
the best of registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
The aggregate market value of the registrant's common stock, without
par value, held by nonaffiliates on March 1, 2001, was $2,167,204,320 (based on
the closing price of such stock).
On March 1, 2001, 80,647,952 shares of the registrant's common stock,
without par value, were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE. Portions of the definitive Proxy Statement
for the 2001 Annual Meeting of Stockholders are incorporated by reference into
Part III. The sections of the Proxy Statement labeled "Committee Report on
Executive Compensation" and "Cumulative Total Shareholder Return" are expressly
not incorporated into this document.
TABLE OF CONTENTS
HEADING PAGE
PART II
Item 6. SELECTED FINANCIAL DATA................................................................................. 2
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION............................................................................................... 3
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK............................................. 14
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K................................................................................ 17
SIGNATURES....................................................................................................... 55
ITEM 6. SELECTED FINANCIAL DATA (RESTATED)
2000 1999 1998 1997 1996
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(In Thousands, Except Per Share Amounts)
Revenues $1,266,153 $924,219 $906,256 $936,337 $817,981
Operating expenses
Cost of natural gas and other products sold 562,229 352,554 367,932 399,941 314,271
Operating and maintenance 251,477 221,082 208,190 205,723 196,389
Depreciation, depletion and amortization 142,491 132,164 118,745 113,063 93,827
Other expenses 61,989 45,580 57,998 61,170 36,390
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Total operating expenses 1,018,186 751,380 752,865 779,897 640,877
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Operating income $247,967 $172,839 $153,391 $156,440 $177,104
=================================================================
Interest and other income $39,463 $78,700 $17,021 $22,481 $11,109
Write-down of investment in partnership (49,700)
Net income $149,477 $96,852 $89,310 $98,630 $100,014
Basic earnings per common share $1.86 $1.17 $1.08 $1.20 $1.22
Diluted earnings per common share $1.85 $1.17 $1.08 $1.19 $1.21
Dividends per share $0.685 $0.67 $0.6525 $0.62 $0.60
Book value per common share $11.79 $10.99 $10.27 $9.79 $8.97
Total assets $2,472,027 $2,184,734 $2,111,540 $1,874,974 $1,757,116
Net cash provided from operating
activities 252,067 207,331 278,005 197,596 177,175
Capital expenditures 315,142 261,983 455,477 208,359 289,314
Capitalization
Long-term debt, less current portion $714,537 $735,043 $615,770 $541,986 $555,509
Redeemable cumulative preferred stock 4,828
Common stock 952,632 894,516 848,752 803,858 736,341
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Total capitalization $1,667,169 $1,629,559 $1,464,522 $1,345,844 $1,296,678
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2
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
SUMMARY
On July 1, 2001, Questar Market Resources (QMR) elected to change its
accounting method for gas and oil properties from the full cost method to the
successful efforts method. The change was prompted by an acquisition of a
company that uses successful efforts. A subsidiary, Wexpro, has always
employed the successful efforts method. Management believes that the
successful efforts method is preferable and will more accurately present the
results of operations of the Company's exploration, development and
production activities, minimizes asset write-downs caused by temporary
declines in gas and oil prices and reflects impairment of the carrying value
of the Company's gas and oil properties only when there has been an
other-than-temporary decline in their fair value.
Prior years financial statements have been retroactively restated to reflect
this change in accounting method. As a result of the change in accounting
method, previously reported earnings decreased $7.2 million ($.09 per share)
and $2.0 million ($.03 per share) for the years ended December 31, 2000 and
1999, respectively, and increased $9.4 million ($.15 per share) for the year
ended December 31, 1998.
Questar Corporation earned $149.5 million in 2000, representing a 54%
improvement over net income reported for 1999. Following is a year to year
comparison of net income by line of business.
2000 1999 Change Percentage
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(Dollars in thousands)
Questar Market Resources (Restated) $77,808 $43,888 $33,920 77%
Questar Regulated Services 54,332 11,079 43,253 390%
Corporate and other operations 17,337 41,885 (24,548) -59%
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$149,477 $96,852 $52,625 54%
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Earnings per diluted common share $1.85 $1.17 $0.68 58%
Questar Market Resources' net income rose 77% in 2000 compared with 1999 due
primarily to higher energy prices, a 10% increase in natural gas production
and increased investment by Wexpro in gas-development properties.
Net income of Questar Regulated Services increased 390% in 2000. In 1999,
Questar Pipeline recorded a write-down of its investment in the TransColorado
partnership and ongoing operating losses from the TransColorado partnership.
Questar Gas received a $13.5 million general rate increase effective August
11, 2000, including $7.1 million of interim rate relief beginning January 1,
2000.
Net income of corporate and other operations decreased 59% in 2000 primarily
as the result of reduced sales of securities. Corporate and other operations
recorded after tax gains from selling securities of $13.8 million in 2000
compared with $36.9 million in 1999.
Repurchase of 3.2 million shares of Questar common stock beginning in April
1999 and continuing through August 2000 increased earnings per share by $.04
in 2000.
3
RESULTS OF OPERATIONS
QUESTAR MARKET RESOURCES (Market Resources) conducts Questar's exploration and
production, gas development, gathering, processing and marketing activities.
Following is a restated summary of financial results and operating information.
YEAR ENDED DECEMBER 31,
2000 1999 1998
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(IN THOUSANDS)
OPERATING INCOME
Revenues
Natural gas sales $193,359 $125,245 $98,767
Oil and natural gas liquids sales 59,901 41,521 36,722
Cost-of-service gas operations 74,492 61,705 61,448
Energy marketing 379,760 243,296 234,565
Gas gathering and processing 29,278 22,341 21,954
Other 5,263 4,203 4,816
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Total revenues 742,053 498,311 458,272
Operating expenses
Energy purchases 369,752 239,201 230,462
Operating and maintenance 106,761 79,719 73,460
Exploration 7,917 5,321 6,069
Depreciation, depletion and amortization 85,025 73,028 64,965
Abandonment and impairment of oil
and gas properties 3,418 7,535 15,137
Other taxes 36,262 21,516 24,988
Wexpro settlement agreement -
oil income sharing 4,758 2,292 1,053
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Total operating expenses 613,893 428,612 416,134
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Operating income $128,160 $69,699 $42,138
===========================================
OPERATING STATISTICS
Production volumes
Natural gas (in MMcf) 68,963 62,712 51,309
Oil and natural gas liquids (in Mbbl)
Questar Exploration & Production 2,225 2,311 2,340
Wexpro 521 555 554
Production revenue
Natural gas (per Mcf) $2.80 $2.00 $1.92
Oil and natural gas liquids (per bbl)
Questar Exploration & Production $20.50 $13.92 $12.70
Wexpro $27.43 $16.84 $12.64
Wexpro investment base, net
of deferred income taxes (in millions) $124.8 $108.9 $97.6
Energy-marketing volumes
(in thousands of equivalent dth) 105,632 112,982 113,513
Natural gas-gathering volumes (in Mdth)
For unaffiliated customers 92,969 84,961 72,908
For Questar Gas 36,791 32,050 29,893
For other affiliated customers 25,068 19,659 17,720
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Total gathering 154,828 136,670 120,521
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Gathering revenue (per dth) $0.13 $0.15 $0.16
4
REVENUES
Revenues were 49% higher in 2000 when compared with 1999 because of higher
prices for natural gas, oil and NGL and increased natural gas production.
Natural gas production rose 10% to 69 Bcf and the average selling price
increased 40%. U. S. gas production increased 3% to 61.7 Bcf, while Canadian
production rose 152% to 7.3 Bcf. Questar acquired Canadian reserves and
producing properties in January 2000. Approximately 53% of gas production in
2000 was hedged at an average price of $2.16 per Mcf, net to the well.
Hedging activities reduced revenues from gas sales by $33.7 million in 2000
but had an insignificant impact in 1999 and 1998.
Selling prices of oil and NGL for nonregulated operations increased 47% to a
combined average of $20.50 per barrel and more than offset a 4% decrease in
production volumes. Approximately 73% of the nonregulated oil production was
hedged at an average price of $17.36 per barrel. Hedging activities reduced
revenues from oil sales by $15.5 million in 2000, but had an insignificant
impact in 1999 and 1998. Production declined in 2000 as a result of selling
nonstrategic properties in the fourth quarter of 1999.
For 2001, Questar has used swaps, costless collars and fixed-price contracts
to hedge approximately 55% of estimated gas production based on December 2000
reserves. The average hedged price is $2.90 per Mcf (net to the well)
assuming floor prices on collars. The average hedged price increases to $3.15
per Mcf (net to the well) if collar ceiling prices are assumed. Approximately
62% of 2001 estimated oil production, based on December 2000 reserves, is
hedged at an average price of $17.20 per barrel, net to the well. Quantities
of hedged production in any given month range between 49% and 66% for gas and
56% and 70% for oil.
Revenues from cost-of-service operations were 21% higher in 2000 compared
with 1999. Wexpro manages and develops oil and natural gas properties on
behalf of Questar Gas and receives a return on its investment in successful
wells. The natural gas production is delivered to Questar Gas at cost of
service. Oil is sold at market prices. Any net income from oil sales
remaining after recovery of expenses and Wexpro's return on investment is
divided between Wexpro and Questar Gas. Questar Gas's portion is reported as
oil-income sharing. Wexpro's investment base, net of deferred income taxes,
grew 15% in 2000 when compared with 1999. The average return on investment
was 19.5% in 2000 and 20% in 1999.
Higher energy prices were responsible for substantial increases in revenues
for energy marketing and improved plant-processing margins. Increased gas
demand led to higher volumes of gas gathering.
Revenues in 1999 improved 9% compared with 1998 as a result of increased
prices for gas, oil and NGL and a 22% rise in gas production. Natural gas
selling prices averaged 4% higher in 1999.
OPERATING EXPENSES (RESTATED)
Operating and maintenance expenses were 34% higher in 2000 primarily due to
an increase in the number of gas and oil properties and increased legal costs
in the settlement of a major case. Exploration expense increased 49% in 2000
compared with 1999 primarily as a result of drilling dry exploratory wells.
Lower dry hole expense caused a 12% decrease in exploration expense in 1999
compared with 1998. Depreciation, depletion and amortization expense (DD&A)
increased 16% in 2000 due largely to a 10% increase in natural gas
production. The average DD&A rate for oil and gas properties was $.78 per
thousand cubic feet equivalent (Mcfe) for 2000, up from $.71 per Mcfe in
1999. Abandonment and impairment of oil and gas properties in 1998 reflects a
write off of assets amounting to $14.7 million as a result of lower energy
prices. Other taxes, primarily production related, rose 69% in 2000 driven by
higher revenues and prices.
5
NONREGULATED GAS AND OIL RESERVES
Market Resources achieved a 261% reserve replacement ratio in 2000 compared
with 131% in 1999. Reserve additions, revisions and purchases, net of sales
in place, amounted to 214.8 Bcfe in 2000, more than double the 100.1 Bcfe
added in 1999. Gains in reserves occurred through drilling results in the
Pinedale Anticline and the acquisition of 61.1 Bcfe of proved reserves in
Canada. In January 2001, Market Resources closed on the sale of 290 producing
properties and a gas gathering system in the Midcontinent for $27 million
with an effective sale date of November 2000. The properties produced
approximately 4.3 MMcf of gas and 180 barrels of oil per day, but were not
compatible with the long-term strategic plans of the Company. In the fourth
quarter of 1999, Market Resources sold producing properties mostly in the
Permian Basin and Kansas with combined daily production of 4.3 MMcf of gas
and 1,100 barrels of oil.
Market Resources achieved a five-year average finding cost of $.82 per Mcfe,
excluding cost-of-service operations, in 2000 compared with $.86 per Mcfe in
1999.
QUESTAR REGULATED SERVICES (Regulated Services) conducts Questar's natural
gas-distribution, transmission, storage and nonregulated retail energy
services.
Natural Gas Distribution - Questar Gas conducts natural gas distribution
operations. Following is a summary of financial results and operating
information:
YEAR ENDED DECEMBER 31,
2000 1999 1998
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(IN THOUSANDS)
OPERATING INCOME
Revenues
Residential and commercial sales $467,293 $396,882 $425,452
Industrial sales 38,993 28,938 29,555
Industrial transportation 6,968 6,594 6,480
Other 23,508 17,523 15,336
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Total revenues 536,762 449,937 476,823
Natural gas purchases 334,193 257,265 281,004
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202,569 192,672 195,819
Margin
Operating expenses
Operating and maintenance 101,486 103,308 96,923
Depreciation and amortization 34,450 36,426 33,261
Other taxes 10,213 7,625 8,185
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Total operating expenses 146,149 147,359 138,369
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Operating income $56,420 $45,313 $57,450
========================================
OPERATING STATISTICS
Natural gas volumes (in Mdth)
Residential and commercial sales 83,373 82,201 83,231
Industrial deliveries
Sales 10,314 9,823 9,681
Transportation 54,836 51,643 55,461
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Total industrial 65,150 61,466 65,142
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Total deliveries 148,523 143,667 148,373
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6
YEAR ENDED DECEMBER 31,
2000 1999 1998
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Natural gas revenue (per dth)
Residential and commercial $5.60 $4.83 $5.11
Industrial sales 3.78 2.95 3.05
Transportation for industrial customers 0.13 0.13 0.12
System natural gas cost (per dth) $3.54 $2.61 $2.57
Heating degree days (normal 5,609) 5,402 5,317 5,462
Warmer than normal 4% 5% 3%
Number of customers at December 31,
Residential and commercial 703,306 684,950 662,084
Industrial 1,323 1,367 1,308
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704,629 686,317 663,392
======================================
MARGIN (REVENUES LESS NATURAL GAS PURCHASES)
Questar Gas' margin increased 5% in 2000 when compared with 1999 after
declining by 2% in the prior- year comparison. The improvement was primarily
the result of a $13.5 million annual general rate increase. A $7.1 million
portion of the Utah rate increase went into effect January 1, 2000, with the
remainder reflected in rates beginning August 11, 2000. The rate case
authorized Questar Gas to earn up to an 11% return on equity and included $5
million for annual gas processing costs. The rate case resolved an issue in
which the Public Service Commission of Utah (PSCU) had denied recovery of
$3.6 million of gas processing costs in 1999.
Usage per residential customer, calculated on a temperature adjusted basis,
decreased in 2000 for the third consecutive year. Usage per residential
customer was three decatherms or 3% lower in 2000 when compared with 1999 and
two decatherms or 1% lower in 1999 compared with 1998. Temperatures have been
warmer than normal for the past seven years. However, since 1995, the
financial impact of warmer weather has been minimized because of a
weather-normalization adjustment in rates. Customers served by Questar Gas
grew by 18,312 or 2.7% in 2000, following growth rates of 3.5% in 1999 and
3.4% in 1998.
Industrial deliveries were 6% higher in 2000 due to an increase in natural
gas volumes used to generate electricity. Gas deliveries to industrial
customers decreased by 6% in 1999 because a major steel-producing customer
reduced operations. Margins from gas delivered to industrial customers,
either sold or transported, are substantially lower than from gas delivered
to residential and commercial customers.
Significant gas-cost increases in the second half of 2000 due to rising
demand for natural gas in the western U. S. did not affect the margin. Under
rate regulation in Utah and Wyoming, Questar Gas can request authorization to
recover from customers the cost of its gas supply on a dollar-for-dollar
basis. Gas costs in Utah rates have risen from $1.72 per dth in 1999 to $2.91
in 2000. As of January 1, 2001, gas costs in rates rose to $4.67 per dth.
OPERATING EXPENSES
Operating and maintenance expenses were 2% lower in 2000 due to decreases in
legal, information technology and labor costs. Questar Gas improved a number
of its information technology systems in 1999 as part of its year 2000
system-readiness program. Labor costs were lower as a result of early
retirement programs effective October 31, 2000, and August 31, 1998.
Operating and maintenance expenses were 7% higher in 1999 due to incremental
costs of serving a growing customer base. Depreciation expense was $2.8
million lower in 2000 due to investments in several information systems being
fully depreciated. Depreciation increased 10% in 1999 because of capital
spending. Other taxes
7
increased in 2000 because of a $1.4 million current-year adjustment of
prior-year taxes and from higher property tax rates.
ACQUISITION OF DISTRIBUTION SYSTEMS
Questar Gas has agreed in principle to acquire two gas distribution systems
in exchange for 390,000 shares of Questar Corporation common stock. The
acquisitions, pending approval from the PSCU and Public Service Commission of
Wyoming (PSCW), will add about 10,500 customers in Utah and Wyoming. The
transactions will be accounted for as a purchase.
Natural Gas Transmission - Questar Pipeline conducts natural gas-transmission
and storage operations. Following is a summary of financial results and
operating information:
Year Ended December 31,
2000 1999 1998
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(IN THOUSANDS)
OPERATING INCOME
Revenues
Transportation $72,547 $69,885 $70,824
Storage 37,711 37,647 36,463
Processing 6,763 3,570
Other 2,055 1,058 1,270
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Total revenues 119,076 112,160 108,557
Operating expenses
Operating and maintenance 43,761 38,534 38,832
Depreciation and amortization 15,391 16,743 13,927
Other taxes 3,071 2,488 2,600
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Total operating expenses 62,223 57,765 55,359
----------------------------------------
Operating income $56,853 $54,395 $53,198
========================================
OPERATING STATISTICS
Natural gas transportation volumes (in Mdth)
For unaffiliated customers 158,604 135,886 120,747
For Questar Gas 108,183 105,499 107,501
For other affiliated customers 8,370 12,153 26,878
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Total transportation 275,157 253,538 255,126
========================================
Transportation revenue (per dth) $0.26 $0.28 $0.28
REVENUES
Revenues rose 6% in 2000 compared with 1999 due to an increase in the demand
charges resulting from a higher quantity of transportation volumes under firm
contracts and a full year of operation of a plant that removes excess carbon
dioxide from the gas stream. The plant began operation mid-year 1999.
The transportation system experienced an increased demand for gas
transportation resulting from colder fourth-quarter temperatures and expanded
usage for regional power generation. As of December 31, 2000, approximately
77% of Questar Pipeline's transportation system was reserved by
firm-transportation customers under contracts with varying terms and lengths.
Questar Gas has reserved transportation capacity from Questar Pipeline of
approximately 828,000 dth per day, representing 69% of the total reserved
daily-transportation capacity at December 31, 2000. This contract, which
accounts for 78% of the demand charges collected by Questar Pipeline, extends
through June 2002.
8
Revenues from storage operations were unchanged in 2000 when compared with
1999 after increasing 3% in 1999. Questar Pipeline's primary storage facility
at Clay Basin in eastern Utah was enlarged in May 1998. The storage facility
is 100% subscribed under long-term contracts. Most of those contractual
volumes have remaining terms of at least nine years. Questar Gas has
contracted for 26% of firm-storage capacity for at least seven years.
OPERATING EXPENSES
Operating and maintenance expense climbed 14% in 2000 compared with 1999. A
full year of expenses associated with a gas-processing plant added $2 million
of expense and legal costs in a case involving the TransColorado pipeline
added $1.8 million. The estimated useful life of the carbon-dioxide removal
plant was increased from 10 to 20 years resulting in a $1.3 million reduction
of depreciation expense in 2000. Because processing fees are determined on a
cost-of-service basis, the lower depreciation expense resulted in a $1.3
million refund to Questar Gas, the primary customer of processing services.
Depreciation expense increased 20% in 1999 resulting from capital investment
in facilities and information-technology systems.
TRANSCOLORADO CASE
Questar TransColorado Inc. (QTC), a subsidiary of Questar Pipeline, and KN
TransColorado, Inc., (KNTC), a subsidiary of Kinder Morgan, are partners in
the TransColorado Gas Transmission Company (TransColorado). The partners are
involved in a complex lawsuit that is pending in a state district court in
Colorado. At the center of the lawsuit is the validity of a contractual right
claimed by QTC to put its 50% interest in TransColorado to KNTC during the
12-month period beginning March 31, 2001. QTC and KNTC entered a standstill
agreement regarding various issues in the litigation. QTC provided notice to
KNTC that it elected to put its interest in TransColorado as of March 31,
2001, were it not for the provisions of the standstill agreement.
Questar Pipeline recorded a $49.7 million pretax write-down of its investment
in the TransColorado partnership in 1999. QTC share of TransColorado's
operating losses ranged from $.3 million to $1.2 million per month.
CORPORATE AND OTHER OPERATIONS - This business segment is responsible for
information-technology and communications services and corporate
administration.
YEAR ENDED DECEMBER 31,
2000 1999 1998
----------------------------------------
(IN THOUSANDS)
OPERATING INCOME
Revenues $73,409 $57,679 $47,907
Operating expenses
Cost of products sold 24,640 9,651 1,515
Operating and maintenance 33,506 37,516 37,113
Depreciation and amortization 7,590 5,953 6,575
Other taxes 1,073 1,071 1,019
----------------------------------------
Total operating expenses 66,809 54,191 46,222
----------------------------------------
Operating income $6,600 $3,488 $1,685
========================================
REVENUES
Revenues increased 27% because of the acquisitions of Consonus of Oregon at
mid-year 2000 and two computer-networking businesses in the second half of
1999. Questar InfoComm is the majority owner of Consonus. Consonus is an
e-commerce business that combines Internet services and network support in
facilities designed to withstand many of the effects of natural disasters.
The gross
9
margin on products and services sold amounted to $8.3 million, $2.6 million
and $2 million in 2000, 1999 and 1998, respectively.
OPERATING EXPENSES
Operating and maintenance expenses were 11% lower in 2000 when compared with
1999. The impact of adding businesses was partially offset by the effect of
an early retirement program in 1999. A $2.9 million charge associated with an
early retirement program was recorded in 1999 when 50 employees elected to
retire. The workforce reduction resulted in a $2.8 million decrease of
operating expenses in 2000. Amortization of goodwill, incurred because of the
acquisition of Consonus, amounted to $1.7 million in 2000.
CONSOLIDATED OPERATING RESULTS (Restated)
REVENUES
Consolidated revenues rose 37% in 2000 compared with 1999 as a result of
higher energy prices, a 10% increase in gas produced from nonregulated
sources and a boost in revenues from e-commerce business. Higher energy
prices increased revenues from gas and oil production, energy marketing,
natural gas distribution and gas plant processing. Consolidated revenues
increased 2% in 1999 compared with 1998 due primarily to increased gas
production, higher selling prices for energy and the revenues from electronic
commerce services. These increases were largely offset by lower revenues from
gas distribution due to lower gas costs collected in rates.
COST OF NATURAL GAS AND OTHER PRODUCTS SOLD
Higher energy prices were apparent in the cost of natural gas and other
products sold. The dominant areas were natural gas purchased for resale to
distribution customers and energy purchases in marketing transactions. In
addition, the cost of e-commerce services increased in 2000. The cost of
natural gas and other products sold was 4% lower in 1999 due to lower gas
costs allowed in distribution rates.
OPERATING AND MAINTENANCE
Operating and maintenance expenses increased by 14% in 2000 when compared
with 1999. Through an acquisition of Canadian properties and development
drilling, Market Resources increased the number of producing properties.
Legal expenses grew in 2000. A major lawsuit involving affiliates of Market
Resources was settled in 2000, while a lawsuit involving affiliates of
Questar Pipeline began in 2000. Operating and maintenance expenses increased
6% in 1999 compared with 1998 resulting from higher costs of serving a
growing number of gas-distribution customers, adding gas and oil producing
properties, and the cost of an early retirement program for
information-technology employees. Labor costs were about $4.6 million lower
in 1999 compared with 1998 as a result of an early retirement program offered
to employees of Regulated Services in 1998.
Questar Regulated Services initiated an early retirement window program
effective October 31, 2000. A total of 262 employees from Questar Gas,
Questar Pipeline and Questar Regulated Services elected to retire. The window
program is projected to result in pretax labor-cost savings for Regulated
Services of $6-8 million yearly.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization (DD&A) increased 8% in 2000 when
compared with 1999 as a result of increased gas production and investment in
depreciable assets. The average DD&A rate for oil and gas wells was $.78 per
thousand cubic feet equivalent (Mcfe) in 2000, up from $.71 per Mcfe in 1999.
Software that reached the end of its depreciable life and an increase of the
estimated useful life of a processing plant resulted in a $4.1 million
reduction of 2000 depreciation expense. DD&A was 11% higher in 1999 as a
result of increased gas production and more investment in exploration and
10
production, distribution and transmission facilities.
EXPLORATION AND ABANDONMENT AND IMPAIRMENT OF OIL AND GAS PROPERTIES
Exploration expense increased 49% in 2000 compared with 1999 primarily as a
result of drilling dry exploratory wells. Lower dry hole expense caused a 12%
decrease in exploration expense in 1999 compared with 1998. Abandonment and
impairment of oil and gas properties in 1998 reflects a write off of assets
amounting to $14.7 million as a result of lower energy prices.
OTHER TAXES
Production and property taxes increased in 2000 because of higher revenues.
Lower revenues in prior years caused a decrease of other taxes in 1999.
Rising property values caused higher property taxes in 2000. A current-year
adjustment of a prior-year tax added $1.4 million to expense in 2000.
INTEREST AND OTHER INCOME
Gain from selling securities of other companies is a significant part of
interest and other income. However, the level of securities sales dropped in
2000 because of the general decline in market value of technology companies.
These sales generated a pretax gain of $26.5 million ($16.3 million after
tax) in 2000 and a pretax gain of $60.7 million ($36.9 million after tax) in
1999.
YEAR ENDED DECEMBER 31,
2000 1999 1998
----------------------------------------
(IN THOUSANDS)
Gain from sales of securities $26,523 $60,720 $10,474
Interest income and other earnings 8,025 7,523 3,087
Gain (loss) from selling properties (1,784) 6,242 142
Allowance for borrowed funds
used during construction 4,476 2,017 1,426
Return earned on working-gas inventory 2,223 2,198 1,892
----------------------------------------
Interest and other income $39,463 $78,700 $17,021
========================================
OPERATIONS OF UNCONSOLIDATED AFFILIATES
Higher energy prices and not repeating TransColorado's operating losses
resulted in earnings in 2000 as opposed to losses the year before. This
income-statement line item included a $49.7 million write-down of investment
in the TransColorado partnership and $5.9 million of operating loss, net of
AFUDC, from TransColorado in 1999.
DEBT EXPENSE
Interest expense increased due to higher short- and long-term borrowing and
to higher interest rates in 2000.
INCOME TAXES
The effective combined federal, state and foreign income tax rate was 34.4%
in 2000, 32.5% in 1999 and 28.8% in 1998. Income tax rates were below the
combined statutory rate of about 38% primarily due to nonconventional fuel
credits, which amounted to $6.5 million in 2000, $7.2 million in 1999 and $8
million in 1998. In addition, a Colorado state income tax credit derived from
conducting business in a designated enterprise zone reduced state income
taxes by $3.2 million in 2000.
11
LIQUIDITY AND CAPITAL RESOURCES
Operating Activities (Restated)
YEAR ENDED DECEMBER 31,
2000 1999 1998
----------------------------------------
(IN THOUSANDS)
Net income $149,477 $96,852 $89,310
Adjustments to net income 173,428 135,981 118,928
Changes in operating assets and liabilities (70,838) (25,502) 69,767
----------------------------------------
Net cash provided from operating activities $252,067 $207,331 $278,005
========================================
Net cash provided from operating activities increased 22% in 2000 when
compared with 1999 due primarily to a 54% increase in net income. Changes in
operating assets and liabilities resulted in a decrease of cash flow due to
the timing differences associated with the effect of higher energy prices on
accounts receivable and the purchased-gas adjustments. This was partially
offset by the change in accounts payable. Interest bearing deposits with
energy brokers, included in accounts receivable, increased significantly in
2000. Net cash provided from operating activities decreased 25% in 1999
compared with 1998 as a result of disbursements on accounts payable. The
balance in payables was higher at the end of 1998 due to construction
projects completed in 1999. The write-downs of investments in partnership and
oil and gas properties were noncash expenses.
Investing Activities (Restated)
Capital expenditures amounted to $315.1 million in 2000 and $262 million in
1999. Capital spending in 2001 is expected to range between $354 million and
$563 million. The upper spending level is contingent upon several key
projects going forward. A 75-mile pipeline planned for central Utah is
awaiting final environmental approval. If approval is received in 2001 and
the pipeline is constructed, Questar Pipeline could spend an additional $74
million. Another major pipeline project, Questar Southern Trails Pipeline
could begin construction in 2001 pending final right of way agreements. This
would further increase capital spending by $45 million. The development of
Questar's e-commerce business is dependent upon the level of outside venture
capital invested.
YEAR ENDED DECEMBER 31,
2001
Forecast 2000 1999
----------------------------------------
(IN THOUSANDS)
Questar Market Resources
Exploratory drilling $2,500 $446 $1,173
Development drilling 76,000 97,361 64,642
Other exploration 2,800 342 13,808
Reserve acquisitions 32,000 65,130 3,704
Production 5,100 8,382 8,746
Gathering and processing 28,000 3,330 12,705
Electric generation 25,000
Storage 7,100 11,513 4,108
General 1,500 855 19,362
----------------------------------------
180,000 187,359 128,248
12
YEAR ENDED DECEMBER 31,
2001
Forecast 2000 1999
----------------------------------------
(IN THOUSANDS)
Questar Regulated Services
Natural gas distribution
Distribution system and
customer additions 49,900 49,454 50,077
General 17,800 16,313 18,370
----------------------------------------
67,700 65,767 68,447
Natural gas transmission
Transmission system 20,700 15,312 11,936
Storage 11,900 333 1,571
Partnerships 7,900 9,024 14,414
Southern Trails Pipeline 13,975 14,639
Processing plant 250 2,912
General 6,600 4,141 4,952
----------------------------------------
47,100 43,035 50,424
----------------------------------------
Other 2,100 1,167 1,385
----------------------------------------
Total Questar Regulated Services 116,900 109,969 120,256
Corporate and other operations
Electronic commerce 49,900 12,878 4,296
Communications and technology 3,100 1,317 3,472
General 3,600 3,619 5,711
----------------------------------------
56,600 17,814 13,479
----------------------------------------
$353,500 $315,142 $261,983
========================================
QUESTAR MARKET RESOURCES
Capital expenditures in 2000 primarily reflected exploration for and
development of gas and oil reserves and a purchase of a Canadian company,
which added 61 Bcfe of proved reserves. Market Resources participated in
drilling 316 wells (94 net wells) in 2000 that resulted in 223 gas wells, 18
oil wells, 21 dry holes and 54 wells in progress at year end. The success
rate was 92%.
QUESTAR REGULATED SERVICES - NATURAL GAS DISTRIBUTION
The distribution system was extended by 964 miles of main, feeder and service
lines to accommodate the addition of 18,312 customers.
QUESTAR REGULATED SERVICES - NATURAL GAS TRANSMISSION
Capital spending focused on expansion of the gas transmission network,
conversion of a crude-oil pipeline to transport gas into Southern California
and the acquisition of an additional 18% interest in a pipeline partnership.
CORPORATE AND OTHER OPERATIONS
Capital expenditures included acquiring e-commerce operations and developing
information- technology facilities.
13
Financing Activities
Cash flow generated from operations plus proceeds from the sales of
securities and release of cash previously held in escrow were used to fund
capital expenditures, reduce short- and long-term borrowings, repurchase
shares of Questar common stock and pay dividends to holders of common stock.
Proceeds from a 1999 sale of nonstrategic gas and oil properties were placed
in an escrow account pending possible reinvestment in other producing
properties.
In April 1999, the Company announced plans to repurchase up to $50 million of
its shares over the next two years. From April 1999 through August 2000, the
Company acquired 3.2 million shares for $51.4 million, with about half of
those purchases occurring in 2000. The Company used part of the $121.9
million in proceeds from its 1999 and 2000 sales of Nextel and other
securities to fund those stock repurchases.
Short-term borrowings amounted to $181.1 million of commercial paper and $28
million of bank loans at December 31, 2000. A year earlier, short-term debt
consisted of $128.4 million of commercial paper and $15.7 million of bank
loans. The weighted average interest rate on balances at December 31 was
6.68% in 2000 and 6.14% in 1999. Parent-company commercial-paper borrowings
are backed by short-term line-of-credit arrangements and rated P1 and A1 by
Moody's and Standard and Poor's, respectively. In the third quarter of 2000,
Market Resources initiated an unrated commercial-paper program with a $100
million capacity. Commercial-paper borrowings are limited to and supported by
available capacity on Market Resources' existing revolving credit facility.
Market Resources had a commercial-paper balance of $12.5 million that was
included in the total $181.1 million balance at December 31, 2000.
On March 6, 2001, Market Resources issued in a public offering $150 million
of 7.5% notes due 2011. Market Resources applied the proceeds of the debt
offering to repay a portion of its outstanding floating-rate debt. In 1999,
Market Resources entered into a long-term revolving-credit facility with a
syndication of banks. The credit facility has a $300 million capacity. Market
Resources had borrowed $244.4 million as of December 31, 2000 under this
arrangement.
On February 27, 2001, Questar Pipeline gave notice that it will redeem $30
million of its 9 7/8% debentures on March 30, 2001. The redemption price is
equal to 104.67% of the principal amount plus interest from December 1, 2000.
The Company typically has negative net working capital at December 31 because
of short-term borrowings. These borrowings are seasonal and generally peak at
year end because of cold-weather gas purchases. Negative working capital at
year end was exacerbated by rising energy prices experienced in the second
half of 2000 and extending into the first quarter of 2001.
Questar's consolidated capital structure consisted of 42% long-term debt and
58% common shareholders' equity at December 31, 2000. Moody's and Standard
and Poor's have rated the long-term debt of Questar Gas and Questar Pipeline
A1 and A+, respectively. Questar Market Resources' debt rating is BBB+ by
Standard and Poor's and Baa2 by Moody's.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Questar's primary market-risk exposures arise from commodity-price changes
for natural gas, oil and other hydrocarbons and changes in long-term interest
rates. The Company has an investment in a foreign operation that may subject
it to exchange-rate risk. Market Resources also has reserved
14
pipeline capacity for which it is obligated to pay $3 million annually for
the next six years, regardless of whether it is able to market the capacity
to others.
HEDGING POLICY
The Company has established policies and procedures for managing market risks
through the use of commodity-based derivative arrangements. A primary
objective of these hedging transactions is to protect the Company's commodity
sales from adverse changes in energy prices. The volume of production hedged
and the mix of derivative instruments employed are regularly evaluated and
adjusted by management in response to changing market conditions and reviewed
periodically by the Board of Directors. Additionally, under the terms of the
Market Resources' revolving credit facility, not more than 75% of Market
Resources' production quantities can be committed to hedging arrangements.
The Company does not enter into derivative arrangements for speculative
purposes.
ENERGY-PRICE RISK MANAGEMENT
Energy-price risk is a function of changes in commodity prices as supply and
demand fluctuate. Market Resources bears a majority of the risk associated
with changes in commodity prices. The Company uses hedge arrangements in the
normal course of business to limit the risk of adverse price movements;
however, these same arrangements usually limit future gains from favorable
price movements.
Market Resources held hedge contracts covering the price exposure for about
50.5 million dth of gas and 1 million barrels of oil at December 31, 2000. A
year earlier the contracts covered 72.1 million dth of natural gas and 2.4
million barrels of oil. The hedging contracts exist for a significant share
of Questar-owned gas and oil production and for a portion of gas-marketing
transactions. The contracts at December 31, 2000, had terms extending through
December 2003, with about 91% of those contracts expiring by the end of 2001.
The mark-to-market adjustment of gas and oil price-hedging contracts at
December 31, 2000 was a negative $98 million and represented a liability owed
to counterparties if terminated. A 10% decline in gas and oil prices would
decrease the mark-to-market adjustment by $18.1 million; while a 10% increase
in prices would increase the mark-to-market adjustment by $18.1 million. The
mark-to-market adjustment of gas and oil price-hedging contracts at December
31, 1999 was a negative $6.2 million. A 10% decline in gas and oil prices at
that time would have caused a positive mark-to-market adjustment of $16.7
million. Conversely, a 10% increase in prices would have resulted in a $16.3
million negative mark-to-market adjustment. The calculations used energy
prices posted on the NYMEX, various "into the pipe" postings and fixed prices
for the indicated measurement dates. These sensitivity calculations do not
consider changes in the fair value of the corresponding scheduled physical
transactions (i.e., the correlation between the index price and the price to
be realized for the physical delivery of gas or oil production), which should
largely offset the change in value of the hedge contracts.
INTEREST-RATE RISK MANAGEMENT
The Company owed $714.9 million of long-term debt at December 31, 2000, of
which $470.5 million was fixed-rate debt. The fair value of fixed-rate debt
is subject to change as interest rates fluctuate. The fair value of Questar's
long-term debt amounted to $735.6 million at December 31, 2000. The Company
owed $735.4 million of long-term debt at December 31, 1999, of which $470.1
million was fixed-rate debt. The fair value of Questar's long-term debt
amounted to $728.3 million at December 31, 1999. The fair-value calculation
was based upon quoted market prices and the discounted present value of cash
flows using the Company's current borrowing rates. If interest rates declined
by 10%, fair value would increase to $758.4 million in 2000 and $753.3
million in 1999. Interest costs paid on variable-rate long-term debt would
decrease about $1.7 million. The sensitivity calculations do not represent
the cost to retire the debt securities. The book value of variable-rate debt
approximates fair value.
15
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 result in a change in value of $3.3
million in 2000 and $9.5 million in 1999.
FOREIGN CURRENCY RISK MANAGEMENT
The Company does not hedge the foreign currency exposure of its foreign
operation's net assets and long-term debt. Long-term debt held by the foreign
operation amounting to $54.4 million (U.S.) is expected to be repaid from
future operations of the foreign company. In January 2000, Market Resources
purchased 100% of the outstanding common stock plus debt of a Canadian
company for $66.4 million (U.S.).
Forward-Looking Statements
This report includes "forward-looking statements" within the meaning of
Section 27(a) of the Securities Act of 1933, as amended, and Section 21(e) of
the Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included or incorporated by reference in this
report, including, without limitation, statements regarding the Company's
future financial position, business strategy, budgets, projected costs and
plans and objectives of management for future operations, are forward-looking
statements. In addition, forward-looking statements generally can be
identified by the use of forward-looking terminology such as "may", "will",
"could", "expect", "intend", "project", "estimate", "anticipate", "believe",
"forecast", or " "continue" or the negative thereof or variations thereon or
similar terminology. Although these statements are made in good faith and are
reasonable representations of the Company's expected performance at the time,
actual results may vary from management's stated expectations and projections
due to a variety of factors.
Important assumptions and other significant factors that could cause actual
results to differ materially from those expressed or implied in
forward-looking statements include changes in general economic conditions,
gas and oil prices and supplies, competition, rate-regulatory issues,
regulation of the Wexpro settlement agreement, availability of gas and oil
properties for sale or for exploration and other factors beyond the control
of the Company. These other factors include the rate of inflation, quoted
prices of securities available for sale, the weather and other natural
phenomena, the effect of accounting policies issued periodically by
accounting standard-setting bodies, and adverse changes in the business or
financial condition of the Company.
16
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a)(1)(2) Financial Statements and Financial Statement Schedules.
The financial statements identified in the List of Financial Statements are
filed as part of this Report.
(a)(3) Exhibits. The following is a list of exhibits required to be
filed as a part of this Report in Item 14(c).
EXHIBIT NO. DESCRIPTION
----------- -----------
2.* Plan and Agreement of Merger dated as of December 16, 1986, by
and among the Company, Questar Systems Corporation, and
Universal Resources Corporation. (Exhibit No. (2) to Current
Report on Form 8-K dated December 16, 1986.)
3.1.* Restated Articles of Incorporation as amended effective May
19, 1998. (Exhibit No. 3.1. to Form 10-Q Report for Quarter
ended June 30, 1998.)
3.2.* Bylaws (as amended effective August 14, 2001). (Exhibit No.
3.2. to Form 10-Q Report for Quarter ended September 30,
2001.)
4.1.*(1) Rights Agreement dated as of February 13, 1996, between the
Company and Chemical Mellon Shareholder Services L.L.C.
pertaining to the Company's Shareholder Rights Plan. (Exhibit
No. 4. to Current Report on Form 8-K dated February 13, 1996.)
4.2.* Questar Dividend Reinvestment and Stock Purchase Plan.
(Exhibit No. 4. to Current Report on Form 8-K dated February
8, 2000.)
10.1.* Stipulation and Agreement, dated October 14, 1981, executed by
Mountain Fuel; Wexpro; the Utah Department of Business
Regulations, Division of Public Utilities; the Utah Committee
of Consumer Services; and the staff of the Public Service
Commission of Wyoming. (Exhibit No. 10(a) to Mountain Fuel
Supply Company's Form 10-K Annual Report for 1981.)
10.2*.(2) Questar Corporation Annual Management Incentive Plan, as
amended and restated effective February 13, 2001. (Exhibit No.
10.2. to Form 10-K Annual Report for 2000.)
10.3.*(2) Questar Corporation Executive Incentive Retirement Plan, as
amended and restated effective May 19, 1998. (Exhibit No.
10.2. to Form 10-Q Report for Quarter Ended June 30, 1998.)
17
10.4.*(2) Questar Corporation Long-Term Stock Incentive Plan, as amended
and restated effective March 1, 2001. (Exhibit No. 10.4. to
Form 10-K Annual Report for 2000.)
10.5.*(2) Questar Corporation Executive Severance Compensation Plan, as
amended and restated effective May 19, 1998. (Exhibit No.
10.3. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.6.*(2) Questar Corporation Deferred Compensation Plan for Directors,
as amended and restated effective October 26, 2000. (Exhibit
No. 10.6. to Form 10-K Annual Report for 2000.)
10.7.*(2) Questar Corporation Supplemental Executive Retirement Plan, as
amended and restated effective June 1, 1998. (Exhibit No.
10.6. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.8.*(2) Questar Corporation Stock Option Plan for Directors, as
amended and restated effective October 29, 1998. (Exhibit No.
10.10. to Form 10-Q Report for Quarter Ended September 30,
1998.)
10.9.*(2) Form of Individual Indemnification Agreement dated February 9,
1993 between Questar Corporation and Directors. (Exhibit No.
10.11. to Form 10-K Annual Report for 1992.)
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.)
10.11.*(2) Questar Corporation Deferred Compensation Plan, as amended and
restated effective October 26, 2000. (Exhibit No. 10.11. to
Form 10-K Annual Report for 2000.)
10.12.*(2) Questar Corporation Directors' Stock Plan as approved May 21,
1996. (Exhibit No. 10.15. to Form 10-Q Report for Quarter
ended June 30, 1996.)
10.13.*(2) Questar Corporation Deferred Share Make-Up Plan. (Exhibit No.
10.8. to Form 10-Q Report for Quarter Ended June 30, 1998.)
10.14.*(2) Questar Corporation Special Situation Retirement Plan.
(Exhibit No. 10.10. to Form 10-Q Report for Quarter Ended June
30, 1998.)
10.15.* Employment Agreement between Questar Corporation and Keith O.
Rattie effective February 1, 2001. (Filed as Exhibit No.
10.15. to Form 10-K Annual
18
Report for 2000.)
21. Subsidiary Information. (Filed as Exhibit No. 21. to Form 10-K
Report for 2000.)
23.01 Consent of Independent Auditors.
24. Power of Attorney. (Filed as Exhibit No. 24. to Form 10-K
Report for 2000.)
99.1. Undertakings for Registration Statements on Form S-3 (No.
33-48168) and on Form S-8 (Nos. 33-4436, 33-15149, 33-40800,
33-40801, 33-48169, 333-04913, and 333-04951). (Filed as
Exhibit No. 99.1. to Form 10-K Report for 2000.)
-----------------------
*Exhibits so marked have been filed with the Securities and Exchange
Commission as part of the indicated filing and are incorporated herein by
reference.
(1)The name of the Rights Agent has been changed to USBank National
Association.
(2)Exhibit so marked is management contract or compensation plan or
arrangement.
(b) The Company did not file any Current Reports on Form 8-K during the
last quarter of 2000.
19
ANNUAL REPORT ON FORM 10-K/A
ITEM 8, ITEM 14(a) (1) and (2), and (d)
LIST OF FINANCIAL STATEMENTS
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
YEAR ENDED DECEMBER 31, 2000
QUESTAR CORPORATION
SALT LAKE CITY, UTAH
FORM 10-K/A -- ITEM 14 (a) (1) AND (2)
QUESTAR CORPORATION AND SUBSIDIARIES
LIST OF FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
The following financial statements of Questar Corporation and subsidiaries are
included in Item 8:
Consolidated statements of income--Years ended December 31, 2000, 1999
and 1998
Consolidated balance sheets--December 31, 2000 and 1999
Consolidated statements of common shareholder's equity--Years ended
December 31, 2000, 1999 and 1998
Consolidated statements of cash flows--Years ended December 31, 2000,
1999 and 1998
Notes to consolidated financial statements
Financial statement schedules, for which provision is made in the applicable
accounting regulations of the Securities and Exchange Commission, are not
required under the related instructions or are inapplicable, and therefore
have been omitted.
20
Report of Independent Auditors
Board of Directors
Questar Corporation
We have audited the accompanying consolidated balance sheets of Questar
Corporation as of December 31, 2000 and 1999, and the related consolidated
statements of income, common shareholders' equity, and cash flows for each of
the three years then ended. 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
Corporation at December 31, 2000 and 1999, and the consolidated results of its
operations and its cash flows for the three years then ended in conformity with
accounting principles generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, in 2000 the
Company changed its method of accounting for oil and gas operations.
/s/ Ernst & Young, LLP
Salt Lake City, Utah
March 6, 2001 except for
Note 1, as to which the
date is November 30, 2001 and
Note 2, as to which the date is July 31, 2001
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Restated)
YEAR ENDED DECEMBER 31,
2000 1999 1998
------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES $1,266,153 $ 924,219 $ 906,256
OPERATING EXPENSES
Cost of natural gas and other products sold 562,229 352,554 367,932
Operating and maintenance 251,477 221,082 208,191
Depreciation, depletion and amortization 142,491 132,164 118,745
Exploration 7,917 5,321 6,069
Abandonment and impairment of oil
and gas properties 3,418 7,535 15,137
Other taxes 50,654 32,724 36,792
------------------------------------------
TOTAL OPERATING EXPENSES 1,018,186 751,380 752,866
------------------------------------------
OPERATING INCOME 247,967 172,839 153,390
INTEREST AND OTHER INCOME 39,463 78,700 17,021
OPERATIONS OF UNCONSOLIDATED
AFFILIATES
Income (loss) 3,996 (4,356) 2,917
Write-down of investment in partnership (49,700)
------------------------------------------
3,996 (54,056) 2,917
DEBT EXPENSE (63,510) (53,944) (47,971)
------------------------------------------
INCOME BEFORE INCOME TAXES 227,916 143,539 125,357
INCOME TAXES 78,439 46,687 36,047
------------------------------------------
NET INCOME $ 149,477 $ 96,852 $ 89,310
==========================================
EARNINGS PER COMMON SHARE
Basic $ 1.86 $ 1.17 $ 1.08
Diluted $ 1.85 $ 1.17 $ 1.08
Average common shares outstanding
Basic 80,412 82,547 82,365
Diluted 80,915 82,676 82,817
See notes to consolidated financial statements
21
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Restated)
ASSETS DECEMBER 31,
2000 1999
----------------------------
(IN THOUSANDS)
CURRENT ASSETS
Cash and cash equivalents $ 9,416 $ 8,291
Accounts receivable 277,331 143,987
Unbilled gas accounts receivable 45,293 37,287
Federal income taxes recoverable 9,694
Inventories, at lower of average cost or market
Gas and oil storage 30,062 27,360
Materials and supplies 10,472 10,254
Purchased-gas adjustments 35,565 432
Prepaid expenses and other 9,189 11,249
----------------------------
TOTAL CURRENT ASSETS 427,022 238,860
PROPERTY, PLANT AND EQUIPMENT
Questar Market Resources 1,400,159 1,225,321
Questar Regulated Services - gas distribution 1,067,362 1,013,599
Questar Regulated Services - gas transmission 731,246 698,236
Questar Regulated Services - other 5,764 4,493
Corporate and other operations 82,603 72,769
----------------------------
3,287,134 3,014,418
LESS ALLOWANCES FOR DEPRECIATION
AND AMORTIZATION
Questar Market Resources 662,923 587,603
Questar Regulated Services - gas distribution 447,496 421,111
Questar Regulated Services - gas transmission 243,006 228,784
Questar Regulated Services - other 3,073 2,542
Corporate and other operations 43,661 40,727
----------------------------
1,400,159 1,280,767
----------------------------
NET PROPERTY, PLANT AND EQUIPMENT 1,886,975 1,733,651
SECURITIES AVAILABLE FOR SALE 33,019 94,945
INVESTMENT IN UNCONSOLIDATED
AFFILIATES 34,505 25,269
OTHER ASSETS
Regulatory assets 37,646 26,025
Goodwill, net 20,514 7,750
Cash held in escrow 5,387 36,727
Other noncurrent assets 26,959 21,507
----------------------------
TOTAL OTHER ASSETS 90,506 92,009
----------------------------
$2,472,027 $2,184,734
============================
22
LIABILITIES AND SHAREHOLDERS' EQUITY
DECEMBER 31,
2000 1999
----------------------------
(IN THOUSANDS)
CURRENT LIABILITIES
Short-term debt $ 209,139 $ 144,115
Accounts payable and accrued expenses
Accounts and other payables 273,892 132,473
Federal income taxes 17,374
Other taxes 30,718 22,315
Deferred income taxes 13,515 164
Interest 7,300 7,518
----------------------------
Total accounts payable and accrued expenses 325,425 179,844
----------------------------
TOTAL CURRENT LIABILITIES 534,564 323,959
LONG-TERM DEBT 714,537 735,043
DEFERRED INCOME TAXES 213,136 189,014
DEFERRED INVESTMENT TAX CREDITS 5,262 5,648
OTHER LONG-TERM LIABILITIES 33,680 29,944
MINORITY INTEREST 18,216 6,610
COMMITMENTS AND CONTINGENCIES - Note 7
COMMON SHAREHOLDERS' EQUITY
Common stock - without par value; 350,000,000
shares authorized; 80,818,274 outstanding at
December 31, 2000 and 81,418,853 outstanding
at December 31, 1999 268,630 278,437
Retained earnings 671,415 577,022
Cumulative other comprehensive income 12,587 39,057
----------------------------
TOTAL COMMON SHAREHOLDERS' EQUITY 952,632 894,516
----------------------------
$2,472,027 $2,184,734
============================
See notes to consolidated financial statements
23
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(Restated)
CUMULATIVE
COMMON STOCK NOTE OTHER COMPRE-
-------------------------- RETAINED RECEIVABLE COMPREHENSIVE HENSIVE
SHARES AMOUNT EARNINGS FROM ESOP INCOME INCOME
----------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
BALANCES AT JANUARY 1, 1998 82,142,084 $ 291,322 $ 499,754 $ (10,173) $ 22,955
Issuance of common stock 521,879 8,243
Purchase of common stock (31,885) (677)
1998 net income 89,310 $ 89,310
Payment of common stock dividends
of $.6525 per share (53,747)
Income tax benefit of dividends paid to ESOP 143
Collection of note receivable from ESOP 6,218
Other comprehensive income
Unrealized loss on securities available for
sale, net of income taxes of $3,086 (4,992) (4,992)
Foreign currency translation adjustment,
net of income taxes of $214 396 396
-----------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 1998 82,632,078 298,888 535,460 (3,955) 18,359 $ 84,714
============
Issuance of common stock 488,302 8,124
Purchase of common stock (1,701,527) (28,575)
1999 net income 96,852 $ 96,852
Payment of common stock dividends
of $.67 per share (55,328)
Income tax benefit of dividends paid to ESOP 38
Collection of note receivable from ESOP 3,955
Other comprehensive income
Unrealized gain on securities available for sale,
net of income taxes of $13,193 21,303 21,303
Foreign currency translation adjustment,
net of income taxes of $327 (605) (605)
---------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 1999 81,418,853 278,437 577,022 - 39,057 $117,550
============
Issuance of common stock 958,232 11,764
Purchase of common stock (1,558,811) (25,543)
2000 net income 149,477 $149,477
Payment of common stock dividends
of $.685 per share (55,084)
Income tax benefit associated with exercise of
nonqualified options and premature dispositions 3,972
Other comprehensive income
Unrealized loss on securities available for sale,
net of income taxes of $16,767 (25,453) (25,453)
Foreign currency translation adjustment,
net of income taxes of $949 (1,017) (1,017)
---------------------------------------------------------------------------------
BALANCES AT DECEMBER 31, 2000 80,818,274 $ 268,630 $ 671,415 $ - $ 12,587 - $123,007
=================================================================================
See notes to consolidated financial statements
24
QUESTAR CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Restated)
YEAR ENDED DECEMBER 31,
2000 1999 1998
----------------------------------------
OPERATING ACTIVITIES (IN THOUSANDS)
Net income $ 149,477 $ 96,852 $ 89,310
Adjustments to reconcile net income to net cash
provided from operating activities
Depreciation, depletion and amortization 148,293 139,124 122,254
Deferred income taxes and investment tax credits 47,355 (1,087) (7,487)
Write-down of investment in partnership 49,700
Abandonment and impairment of oil and gas properties 3,418 7,535 15,137
(Income) loss from unconsolidated affiliates,
net of cash distributions (899) 7,671 (360)
Gain from sales of properties and securities (24,739) (66,962) (10,616)
----------------------------------------
322,905 232,833 208,238
Changes in operating assets and liabilities
Accounts receivable (136,700) (1,004) 8,822
Inventories (2,892) 252 (7,238)
Prepaid expenses and other 2,077 615 2,556
Accounts payable and accrued expenses 144,190 (41,549) 38,207
Federal income taxes (27,068) 8,684 2,251
Purchased-gas adjustments (35,133) 1,635 35,184
Other assets (17,144) 3,446 (7,664)
Other liabilities 1,832 2,419 (2,351)
----------------------------------------
NET CASH PROVIDED FROM OPERATING ACTIVITIES 252,067 207,331 278,005
INVESTING ACTIVITIES
Capital expenditures
Purchase of property, plant and equipment (305,818) (215,814) (421,810)
Other investments (9,324) (46,169) (33,667)
----------------------------------------
Total capital expenditures (315,142) (261,983) (455,477)
Proceeds from disposition of property, plant
and equipment 2,726 45,721 45,613
Proceeds from sales of securities 46,814 75,126 6,759
----------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (265,602) (141,136) (403,105)
FINANCING ACTIVITIES
Issuance of common stock 15,736 8,124 8,243
Purchase of Questar common stock (25,543) (28,575) (677)
Issuance of long-term debt 61,725 317,000 152,743
Repayment of long-term debt (80,075) (206,996) (77,198)
Increase (decrease) in short-term loans 64,581 (76,985) 89,900
Cash held in escrow 31,340 (36,727)
Other financing 2,955 3,993 6,361
Payment of dividends (55,084) (55,328) (53,747)
----------------------------------------
NET CASH PROVIDED FROM (USED IN)
FINANCING ACTIVITIES 15,635 (75,494) 125,625
Foreign currency translation adjustment (975) 101 (307)
----------------------------------------
CHANGE IN CASH AND CASH EQUIVALENTS 1,125 (9,198) 218
BEGINNING CASH AND CASH EQUIVALENTS 8,291 17,489 17,271
----------------------------------------
ENDING CASH AND CASH EQUIVALENTS $ 9,416 $ 8,291 $ 17,489
========================================
See notes to consolidated financial statements
25
QUESTAR CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Accounting Policies
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements contain
the accounts of Questar Corporation and subsidiaries (Questar or the
Company). Questar is a diversified natural gas company with two principal
lines of business: nonregulated and regulated. The Company's nonregulated
activities of gas and oil exploration and production, gas gathering and
processing, and energy marketing are conducted by Questar Market Resources,
Inc. and subsidiaries (Market Resources). The Company's regulated activities
of natural gas distribution, transmission and storage operations are
conducted by Questar Regulated Services Co. and subsidiaries (Regulated
Services). Natural gas-distribution activities are conducted by Questar Gas.
Questar Pipeline provides natural gas transmission and storage services.
Regulated Services also includes Questar Energy Services which conducts
retail-energy services. Corporate and other operations include
information-technology and telecommunication services and corporate
activities. All significant intercompany accounts and transactions have been
eliminated in consolidation.
INVESTMENTS IN UNCONSOLIDATED AFFILIATES: Questar uses the equity method to
account for investments in affiliates in which it does not have control.
Principal affiliates and percentage ownership include: Overthrust Pipeline
Company (72%), TransColorado Gas Transmission Company (50%), Canyon Creek
Compression Company (15%) and Blacks Fork Gas Processing Company (50%).
Generally, the Company's investment in these affiliates equals the underlying
equity in net assets, except for TransColorado where the investment was
written down. The Company experienced an other-than-temporary decline in its
partnership investment in TransColorado caused by low volumes resulting from
unfavorable regional transportation economics.
REGULATION: Questar Gas is regulated by the Public Service Commission of Utah
(PSCU) and the Public Service Commission of Wyoming (PSCW). While Questar Gas
also serves a small area of southeastern Idaho, the Public Utilities
Commission of Idaho has deferred to the PSCU for rate oversight of this area.
Questar Pipeline is regulated by the Federal Energy Regulatory Commission
(FERC). These regulatory agencies establish rates for the storage,
transportation and sale of natural gas. The regulatory agencies also
regulate, among other things, the extension and enlargement or abandonment of
jurisdictional natural gas facilities. Regulation is intended to permit the
recovery, through rates, of the cost of service, including a return on
investment.
The financial statements of rate-regulated businesses are presented in
accordance with regulatory requirements. Methods of allocating costs to time
periods, in order to match revenues and expenses, may differ from those of
other businesses because of cost-allocation methods used in establishing
rates.
USE OF ESTIMATES: The preparation of financial statements in conformity with
accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the amounts of
assets and liabilities and disclosure of contingent liabilities reported in
the financial statements and accompanying notes. Actual results could differ
from those estimates.
REVENUE RECOGNITION: Revenues are recognized in the period that services are
provided or products are delivered. Questar Gas records gas-distribution
revenues for gas delivered to residential and commercial customers but not
billed at the end of the accounting period. Rate-regulated companies
periodically collect revenues subject to possible refunds pending final
orders from regulatory agencies. These companies establish appropriate
reserves for revenues collected subject to refund. The Company's exploration
and production operations use the sales method of accounting for gas
revenues, whereby revenue is recognized on all gas sold to purchasers. A
liability is recorded to the extent that the Company has an imbalance in
excess of its share of remaining reserves in an underlying property. The
Company's net gas imbalances at December 31, 2000 and 1999 were not
significant.
PURCHASED-GAS ADJUSTMENTS: Questar Gas accounts for purchased-gas costs in
accordance with
26
procedures authorized by the PSCU and PSCW under which purchased-gas costs
that are different from those provided for in present rates are accumulated
and recovered or credited through future rate changes.
CASH AND CASH EQUIVALENTS: Cash equivalents consist principally of repurchase
agreements with maturities of three months or less. In almost all cases, the
repurchase agreements are highly liquid investments in overnight securities
made through commercial bank accounts that result in available funds the next
business day.
SECURITIES AVAILABLE FOR SALE: The value of securities available for sale
approximates fair value at the balance sheet date based on published share
prices. Based on market value at the balance sheet date, the Company records
unrealized gains or losses, net of income taxes, as a separate component of
other comprehensive income in shareholders' equity. Gains or losses resulting
from the sale of securities are included in the determination of income as
incurred.
CHANGE IN METHOD OF ACCOUNTING FOR GAS AND OIL PROPERTIES: On July 1, 2001,
Questar elected to change its accounting method for gas and oil properties
from the full cost method to the successful efforts method. The change was
prompted by an acquisition of a company that uses successful efforts. A
subsidiary, Wexpro, has always employed the successful efforts method.
Management believes that the successful efforts method is preferable and will
more accurately present the results of operations of the Company's
exploration, development and production activities, minimizes asset
write-downs caused by temporary declines in gas and oil prices and reflects
impairment of the carrying value of the Company's gas and oil properties only
when there has been an other-than-temporary decline in their fair value.
As a result, prior years and interim financial statements have been
retroactively restated to reflect this change in accounting method. The
effect, net of income taxes, was a reduction of retained earnings recorded
retroactively as of December 31, 1995, of $37.6 million. This resulted from a
reduction of net property, plant and equipment in the amount of $61.9 million
and a reduction of deferred income taxes of $24.3 million. As a result of the
change in accounting method, previously reported earnings decreased $7.2
million ($.09 per share) and $2.0 million ($.03 per share) for the years
ended December 31, 2000 and 1999, respectively, and increased $9.4 million
($.15 per share) for the year ended December 31, 1998.
PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment is stated at
cost. The Company uses the successful efforts accounting method for its gas
and oil exploration and development activities.
OIL AND GAS PROPERTIES
Under the successful efforts method of accounting, the Company capitalizes
all costs related to property acquisitions, successful exploratory wells, and
successful and unsuccessful development wells. Also, the costs of related
support equipment and facilities are capitalized. The costs of unsuccessful
exploratory wells are expensed when such wells are determined to be
nonproductive. Unproved leaseholds costs are capitalized and reviewed
periodically for impairment. Costs related to impaired prospects are charged
to expense. Costs of geological and geophysical studies and other exploratory
activities are expensed as incurred. Costs associated with production and
general corporate activities are expensed in the period incurred. The Company
recognizes gain or loss on the sale of properties on a field basis.
Leasehold costs are amortized on the unit-of-production method based on
proved reserves on a field basis. All other capitalized costs associated with
oil and gas properties are depreciated on the unit-of-production method based
on proved developed reserves on a field basis. Costs of future site
restoration, dismantlement, and abandonment for producing properties are
accrued as part of depreciation, depletion and amortization expense for
tangible equipment by assuming no salvage value in the calculation of the
unit of production rate.
COST-OF-SERVICE OIL AND GAS OPERATIONS
As ordered by the Public Service Commission of Utah, the successful efforts
method of accounting is utilized with respect to costs associated with
certain "cost of service" oil and gas properties managed and developed by
Wexpro and regulated for ratemaking purposes. Cost of service oil and gas
properties are those properties for which the
27
operations and return on investment are regulated by the Wexpro settlement
agreement (see Note 10). In accordance with the settlement agreement,
production from the gas properties operated by Wexpro is delivered to Questar
Gas at Wexpro's cost of providing this service. That cost includes a return
on Wexpro's investment. Oil produced from the cost of service properties is
sold at market prices. Proceeds are credited, pursuant to the terms of the
settlement agreement, allowing Questar Gas to share in the proceeds for the
purpose of reducing natural gas rates.
Capitalized costs are amortized on an individual field basis using the
unit-of-production method based upon proved developed oil and gas reserves
attributable to the field. Costs of future site restoration, dismantlement,
and abandonment for producing properties are accrued as part of depreciation
and amortization expense for tangible equipment by assuming no salvage value
in the calculation of the unit of production rate.
2000 1999
---------------------------
(IN THOUSANDS)
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties - successful efforts accounting
Proved properties (Restated) $ 845,485 $ 717,147
Unproved properties, not being amortized (Restated) 55,608 51,624
Support equipment and facilities 13,179 13,408
---------------------------
914,272 782,179
Cost-of-service oil and gas properties -
successful efforts accounting 348,403 318,451
Gathering, processing and marketing 137,484 124,691
---------------------------
$ 1,400,159 $ 1,225,321
===========================
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
Oil and gas properties - successful efforts
accounting (Restated) $ 411,506 $ 353,399
Cost-of-service oil and gas properties -
successful efforts accounting 193,029 180,867
Gathering, processing and marketing 58,388 53,337
---------------------------
$ 662,923 $ 587,603
===========================
For the remaining Company properties, the provision for depreciation, depletion
and amortization is based upon rates that will systematically charge the costs
of assets against income over the estimated useful lives of those assets. The
investment in natural gas distribution, transmission, storage, gathering and
processing property, plant and equipment, and is charged to expense using the
straight-line method. The costs of gas wells and related production facilities
are charged to expense using the unit-of-production method.
Average depreciation, depletion and amortization rates used in the 12 months
ended December 31 were as follows:
2000 1999 1998
---------------------------------------
Questar Market Resources
Oil and gas properties, per Mcf equivalent (Restated)
U.S. $ 0.73 $ 0.72 $ 0.74
Canada (in U.S. dollars) 1.12 0.63 0.71
Combined U.S. and Canada 0.78 0.71 0.74
Cost of service oil and gas properties, per Mcfe 0.44 0.42 0.39
28
Average depreciation and amortization rates used were as follows:
2000 1999 1998
---------------------------------------
Questar Regulated Services
Natural gas distribution
Distribution plant 4.0% 4.2% 4.3%
Gas wells, per Mcf $ 0.15 $ 0.15 $ 0.17
Natural gas transmission, processing and storage 3.2% 3.4% 3.2%
SFAS 121
The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed Of" in evaluating impairment of
properties.
GOODWILL: Goodwill is amortized on the straight-line method principally over
10 years. Goodwill amortization expense was $1.7 million in 2000 and the
accumulated amortization balance was $1.8 million at December 31, 2000.
CAPITALIZED INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION:
Questar's regulated subsidiaries capitalize the cost of capital employed
during the construction period of plant and equipment in accordance with FERC
guidelines. Capitalized financing costs, called allowance for funds used
during construction (AFUDC), consist of debt and equity portions. The debt
portion of AFUDC is recorded as a reduction of interest expense and the
equity portion is recorded in other income. The Company's nonregulated
subsidiaries capitalize interest costs during construction of assets when it
is applicable. Under provisions of the Wexpro settlement agreement, the
Company capitalizes AFUDC on cost-of-service construction projects and
records the amount in other income. Debt expense was reduced by $4,224,000 in
2000, $3,035,000 in 1999 and $1,421,000 in 1998. AFUDC included in interest
and other income amounted to $4,476,000 in 2000, $2,017,000 in 1999 and
$1,426,000 in 1998.
REACQUISITION OF DEBT: Gains and losses on the reacquisition of debt by
rate-regulated affiliates are deferred and amortized as debt expense over the
would-be remaining life of the retired debt or the life of the replacement
debt in order to match regulatory treatment.
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. Adjustments
resulting from such translations are reported as a separate component of
other comprehensive income in shareholders' equity. Deferred income taxes
have been provided on translation adjustments because the earnings are not
considered to be permanently invested.
HEDGING POLICY: The Company has established policies and procedures for
managing market risks through the use of commodity-based derivative
arrangements. A primary objective of these hedging transactions is to protect
the Company's commodity sales from adverse changes in energy prices. The
volume of production hedged and the mix of derivative instruments employed
are regularly evaluated and adjusted by management in response to changing
market conditions and reviewed periodically by the Board of Directors.
Additionally, under the terms of Market Resources' revolving credit facility,
not more than 75% of Market Resources' production quantities can be committed
to hedging arrangements. The Company does not enter into derivative
arrangements for speculative purposes.
ENERGY-PRICE RISK MANAGEMENT: Market Resources enters into swaps, futures
contracts or options agreements to hedge exposure to price fluctuations in
connection with marketing of the Company's natural gas and oil production,
and to secure a known margin for the purchase and resale of gas, oil and
electricity in marketing activities. It is expected that there is a high
degree of correlation between the changes in market value of such contracts
and the market price ultimately received on the hedged physical transactions.
The timing of production and of the hedge contracts is closely matched. Hedge
prices are established in the areas of Market Resources' production
operations.
29
The Company settles most contracts in cash and recognizes the gains and
losses on hedge transactions during the same time period as the related
physical transactions. Cash flows from the hedge contracts are reported in
the same category as cash flows from the hedged assets. Contracts which do
not have high correlation with the related physical transactions are
marked-to-market and recognized in the current-period income.
INTEREST-RATE RISK MANAGEMENT: The Company borrows funds under both fixed and
variable interest rate arrangements. Variable-rate agreements expose the
Company to market risk related to changes in interest rates.
CREDIT RISK: The Company's primary market areas are the Rocky Mountain
regions of the United States and Canada and the Midcontinent region of the
United States. Exposure to credit risk may be impacted by the concentration
of customers in these regions due to changes in economic or other conditions.
Customers include individuals and numerous industries that may be affected
differently by changing conditions. Management believes that its
credit-review procedures, loss reserves, customer deposits and collection
procedures have adequately provided for usual and customary credit-related
losses. Commodity-based hedging arrangements also expose the Company to
credit risk. The Company monitors the creditworthiness of its counterparties,
which generally are major financial institutions, and believes that losses
from non-performance are unlikely to occur.
INCOME TAXES: Questar files income tax reports on a consolidated basis in
accordance with the Internal Revenue Code and associated regulations.
Questar's subsidiaries account for income taxes on a separate-return basis.
Rate-regulated operations record cumulative increases in deferred taxes as
income taxes recoverable from customers. Questar Gas and Questar Pipeline
have adopted procedures with their regulatory commissions to include
under-provided deferred taxes in customer rates on a systematic basis.
Questar Gas and Questar Pipeline use the deferral method to account for
investment tax credits as required by regulatory commissions.
EARNINGS PER SHARE: The Company presents basic and diluted earnings per share
(EPS) on the income statement. Basic EPS are computed by dividing net income
available to common shareholders by the weighted average number of common
shares outstanding during the accounting period. Diluted EPS includes the
potential dilution from exercising stock options, which is the reason for the
difference between the number of basic and diluted average shares outstanding.
COMPREHENSIVE INCOME: Comprehensive income is the sum of net income as
reported in the Consolidated Statement of Income and other comprehensive
income transactions reported in the Consolidated Statement of Shareholders'
Equity. Other comprehensive income transactions that currently apply to
Questar result from changes in the market value of securities held 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 fair
value. Income is realized when the securities available for sale are sold.
Income taxes associated with realized gains from selling securities available
for sale, which were included in other comprehensive income in prior years,
were $10.2 million in 2000, $23.4 million in 1999 and $1.9 million in 1998.
Beginning in 2001, other comprehensive income will include mark-to-market
adjustments of the Company's qualified energy derivatives. The balances of
cumulative other comprehensive income (loss) for the 12 months ended
December 31, were as follows:
2000 1999
-------------------------
(IN THOUSANDS)
Unrealized gain on securities $13,832 $39,285
Foreign currency translation adjustment (Restated) (1,245) (228)
-------------------------
Cumulative other comprehensive income $12,587 $39,057
=========================
BUSINESS SEGMENTS: Questar's line-of-business disclosures are presented based on
the way senior management evaluates the performance of its business segments.
Certain intersegment sales include intercompany profit.
30
NEW ACCOUNTING STANDARD: The Company is required to adopt the accounting
provisions of Statement of Financial Accounting Standards 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133)
beginning in January 2001. SFAS 133 addresses the accounting for derivative
instruments, including certain derivative instruments embedded in other
contracts. Under the standard, entities are required to carry all derivative
instruments in the balance sheet at fair value. The accounting for changes in
fair value, which result in gains or losses, of a derivative instrument
depends on whether such instrument has been designated and qualifies as part
of a hedging relationship and, if so, depends on the reason for holding it.
If certain conditions are met, entities may elect to designate a derivative
instrument as a hedge of exposure to changes in fair value, cash flows or
foreign currencies. If the hedged exposure is a fair-value exposure, the gain
or loss on the derivative instrument is recognized in earnings in the period
of the change together with the offsetting loss or gain on the hedged item
attributable to the risk being hedged. If the hedged exposure is a cash-flow
exposure, the effective portion of the gain or loss on the derivative
instrument is reported initially as a component of other comprehensive income
in the shareholders' equity section of the balance sheet and subsequently
reclassified into earnings when the forecasted transaction affects earnings.
Any amounts excluded from the assessment of hedge effectiveness, as well as
the ineffective portion of the gain or loss, is reported in earnings
immediately.
As of January 1, 2001, the Company structured a majority of its energy
derivative instruments as cash flow hedges. As a result of adopting SFAS 133
in January 2001, the Company expects to record a liability for derivative
instruments of approximately $121 million. The offset to this amount, net of
income taxes, will be recorded as a loss in other comprehensive income in the
shareholders' equity section of the balance sheet. The fair-value calculation
does not consider changes in fair value of the corresponding scheduled
physical transactions. The Company has identified a number of contracts that
are derivative instruments as defined by SFAS 133, but are specifically
excluded from the provisions of SFAS 133 on the basis of normal sales and
purchase transactions. These contracts are primarily located in the natural
gas distribution and transmission activities.
RECLASSIFICATIONS: Certain reclassifications were made to the 1999 and 1998
financial statements to conform with the 2000 presentation.
NOTE 2 - SUBSEQUENT EVENT - ACQUISITION
Market Resources acquired 100% of the common stock of Shenandoah Energy, Inc.
(SEI) on July 31, 2001 for $403 million in cash including assumed debt. SEI
was a privately held Denver-based exploration, production, gathering and
drilling company. Market Resources obtained an estimated 415 billion cubic
feet equivalent of proved oil and gas reserves, gas processing capacity of
100 MMcf per day, 90 miles of gathering lines, 114,000 acres of net
undeveloped leasehold acreage and four drilling rigs. SEI operations are
located primarily in the Uintah Basin of eastern Utah. The transaction was
accounted for as a purchase business combination in accordance with
accounting principles generally accepted in the United States. The purchase
price in excess of the estimated fair value of the assets was assigned to
goodwill. The acquisition was financed through bank borrowings.
31
Note 3 - Debt
Questar has short-term line-of-credit arrangements with several banks under
which it may borrow up to $220 million. These lines have interest rates
generally below the prime interest rate. Commercial paper borrowings are backed
by the short-term line-of-credit arrangements. The details of short-term debt
are as follows:
DECEMBER 31,
2000 1999
------------------------------
(In Thousands)
Commercial paper with variable interest rates $181,100 $128,379
Bank loans with variable interest rates 28,039 15,736
------------------------------
$209,139 $144,115
==============================
Weighted average interest rate at December 31 6.68% 6.14%
The details of long-term debt are as follows:
DECEMBER 31,
2000 1999
------------------------------
(IN THOUSANDS)
Questar Market Resources
Revolving-credit loan due 2001- 2005 with variable
interest rates (7.01% at December 31, 2000) $244,377 $264,894
Questar Regulated Services - Natural gas distribution
Medium-term notes 6.85% to 8.43%, due 2007
to 2024 225,000 225,000
Questar Regulated Services - Natural gas transmission
Medium-term notes 5.85% to 7.55%, due 2008
to 2019 130,400 130,400
9 3/8% debentures due 2021 85,000 85,000
9 7/8% debentures due 2020 30,000 30,000
Corporate and other 148 155
------------------------------
Total long-term debt outstanding 714,925 735,449
Less current portion 8 7
Less unamortized debt discount 380 399
------------------------------
$714,537 $735,043
==============================
Maturities of long-term debt for the five years following December 31, 2000, in
thousands of dollars are as follows:
2001 $8
2002 6,977
2003 16,978
2004 186,980
2005 6,981
Cash paid for interest was $66,833,000 in 2000, $56,019,000 in 1999 and
$49,430,000 in 1998.
As of December 31, 2000, Questar Pipeline guaranteed $100 million of
long-term debt borrowed by TransColorado Gas Transmission Company. The
partnership has borrowed $200 million under a three-year revolving-credit
arrangement that will expire unless renewed by October 2001.
32
Market Resources revolving-credit loan contains covenants specifying a
minimum amount of net equity and a maximum ratio of debt to equity. On March
6, 2001, Market Resources issued in a public offering $150 million of 7.5%
notes due 2011. Market Resources applied the proceeds of the debt offering to
repay a portion of its outstanding floating-rate debt. On February 27, 2001,
Questar Pipeline gave notice that it will redeem $30 million of its 9 7/8%
debentures on March 30, 2001. The redemption price is equal to 104.67% of the
principal amount plus interest from December 1, 2000.
Note 4 - Common Stock
Dividend Reinvestment and Stock Purchase Plan: The Dividend Reinvestment and
Stock Purchase Plan (Reinvestment Plan) allows parties interested in owning
Questar common stock to reinvest dividends or invest additional funds in
common stock. The Company can use unissued shares or purchase shares in the
open market in order to meet shareholders' purchase demands. The Reinvestment
Plan issued total shares of 322,062, 371,985 and 329,794 in 2000, 1999 and
1998, respectively. At December 31, 2000, 1,920,761 shares were reserved for
future issuance.
Employee Investment Plan: The Employee Investment Plan (Plan) allows eligible
employees to purchase shares of Questar Corporation common stock or other
investments through payroll deduction. Since January 1, 1999, the Company has
matched 80% of employees-pretax purchases up to a maximum of 6%. Prior to
that date, the Company matched 75% of employees' eligible contributions. The
Company's expense equals its matching contribution. Questar's expense and
contribution to the Plan amounted to $5,042,000, $4,713,000 and $4,542,000
for the years ended December 31, 2000, 1999 and 1998, respectively.
Stock Plans: The Company has a Long-term Stock Incentive Plan for officers
and employees and a Stock Option Plan for nonemployee directors (Stock
Plans). The number of shares made available for a given year for options or
other stock awards under the Long-term Stock Incentive Plan is 1% of the
outstanding shares of common stock on the first day of the calendar year. The
current plan was amended March 1, 2011, subject to shareholders approval. The
option price equals the market price of the stock on the grant date. Stock
options for employees have a 10-year life and vest in four equal annual
installments beginning six months after grant date. Nonemployee directors may
receive shares of common stock instead of cash in payment for directors fees
under a separate plan. At December 31, 2000 there were 90,729 shares
available for future issuance under this plan.
No compensation expense is recorded for stock options issued to employees or
directors because the exercise price equals the market price on the date of
issue. If compensation expense had been recorded, it would be based on an
estimate of the fair value of stock options granted and would reduce earnings
per share by $.03 in 2000 and 1998 and $.02 in 1999. For purposes of the
pro-forma expense, the weighted average fair value of the options was
amortized over the vesting period. The pro-forma estimates rely upon
subjective assumptions and the use of a mathematical model to estimate value,
and may not be representative of future results.
33
Transactions involving option shares in the Stock Plans are summarized as
follows:
WEIGHTED AVERAGE
SHARES PRICE RANGE EXERCISE PRICE
--------------------------------------------------
Balance at January 1, 1998 2,940,610 $9.81 -$19.13 $16.22
Granted 857,800 21.38 21.38
Cancelled (77,200) 13.69 - 21.38 17.33
Exercised (437,209) 9.81 - 16.81 14.72
--------------------------------------------------
Balance at December 31, 1998 3,284,001 9.81- 21.38 17.74
--------------------------------------------------
Granted 866,400 17.00 17.00
Cancelled (82,900) 9.81 - 21.38 17.94
Exercised (138,445) 9.81 - 16.81 14.44
--------------------------------------------------
Balance at December 31, 1999 3,929,056 9.81 - 21.38 17.69
--------------------------------------------------
Granted 1,289,050 15.00 15.00
Cancelled (89,254) 13.69 - 21.38 17.19
Exercised (1,301,361) 9.81 - 21.38 15.99
--------------------------------------------------
Balance at December 31, 2000 3,827,491 $9.81 -$21.38 $17.37
==================================================
Exercisable at December 31, 2000 2,464,368 $17.98
Available for future grant at December 31, 2000 1,191,636
The stock options at December 31, 2000 had a weighted average remaining life
of 4.6 years. The fair value of the stock options was determined on the grant
date using the Black-Scholes option-valuation model. The calculated fair
value of options granted and major assumptions used in the model at the date
of grant were as follows:
2000 1999 1998
-----------------------------------------
Fair value of options at grant date $3.38 $3.16 $3.94
Risk-free interest rate 6.79% 5.11% 5.56%
Expected price volatility 25.1% 20.6% 20.2%
Expected dividend yield 4.53% 3.88% 3.09%
Expected life in years 7.0 7.2 4.4
In addition to stock options, the Company issued restricted shares to officers
and employees as part of its payment of bonuses. Compensation expense is
recorded when the bonus is earned. Restricted stock vests in two equal, annual
installments beginning one year after grant. Stock is issued at the market price
on date of grant. Recipients of restricted stock awards are entitled to full
voting rights and receipt of dividends.
2000 1999 1998
----------------------------------------
Shares of restricted stock awarded 46,053 16,919 7,620
Market price at award date $28.01 $15.00 $17.00
Shareholder Rights: On February 13, 1996, Questar's Board of Directors
declared a stock-right dividend for each outstanding share of common stock.
The stock rights were issued March 25, 1996. The rights become exercisable if
a person, as defined, acquires 15% or more of the Company's common stock or
announces an offer for 15% or more of the common stock. Each right initially
represents the right to buy one share of the Company's common stock for
$87.50. Once any person acquires 15% or more of the Company's common stock,
the rights are automatically modified. Each right not owned by the 15% owner
becomes exercisable for the number of shares of Questar's stock that have a
market value equal to two times the exercise price of the right. This same
result occurs if a 15% owner acquires the Company through a reverse merger
when Questar and its stock survive. If the Company is involved in a merger or
other business combination at any time after the rights become exercisable,
rightsholders will be entitled to
34
buy shares of common stock in the acquiring company having a market value
equal to twice the exercise price of each right. The rights may be redeemed
by the Company at a price of $.005 per right until 10 days after a person
acquires 15% ownership of the common stock. The rights expire March 25, 2006.
Note 5 - Financial Instruments and Risk Management
The carrying value and estimated fair values of the Company's financial
instruments were as follows:
DECEMBER 31, 2000 DECEMBER 31, 1999
---------------------------------------------------------
CARRYING ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE VALUE FAIR VALUE
---------------------------------------------------------
(IN THOUSANDS)
Financial assets
Cash and cash equivalents $9,416 $9,416 $8,291 $8,291
Financial liabilities
Short-term loans 209,139 209,139 144,115 144,115
Long-term debt 714,545 735,554 735,050 728,273
Gas and oil price-hedging contracts (98,000) (6,200)
The Company used the following methods and assumptions in estimating fair
values: CASH AND CASH EQUIVALENTS AND SHORT-TERM LOANS - the carrying amount
approximates fair value; LONG-TERM DEBT - the carrying amount of
variable-rate debt approximates fair value. The fair value of fixed-rate debt
is based on quoted market prices, and on the discounted present value of cash
flows using the Company's current borrowing rates; GAS AND OIL PRICE-HEDGING
CONTRACTS - the mark-to-market adjustment of contracts is based on market
prices as posted on the NYMEX from the last trading day of the year.
The average price of the oil contracts at December 31, 2000, was $18.30 per
barrel and was based on the average of fixed amounts in contracts which
settle against the NYMEX. All oil contracts relate to Company-owned
production where basis adjustments would result in a net to the well price of
$17.20 per barrel. The average price of the gas contracts at December 31,
2000 was $3.87 per MMBtu representing the average of contracts with different
terms including fixed, various "into the pipe" postings and NYMEX references.
Gas-hedging contracts were in place for Market Resources-owned production and
gas-marketing transactions. Removing transportation and heat-value
adjustments on the hedges of Company-owned gas as of December 31, 2000, would
result in a price between $2.90 and $3.15 per Mcf, net back to the well.
Fair value is calculated at a point in time and does not represent the amount
the Company would pay to retire the debt securities. In the case of gas and
oil price-hedging activities, the fair value calculation does not consider
the the fair value of the corresponding scheduled physical transactions
(i.e., the correlation between the index price and the price to be realized
for the physical delivery of gas or oil production).
ENERGY-PRICE RISK MANAGEMENT
Market Resources held hedge contracts covering the price exposure for about
50.5 million dth of gas and 1 million barrels of oil at December 31, 2000. A
year earlier the contracts covered 72.1 million dth of natural gas and 2.4
million barrels of oil. The hedging contracts exist for a significant share
of Questar-owned gas and oil production and for a portion of gas-marketing
transactions. The contracts at December 31, 2000, had terms extending through
December 2003, with about 91% of those contracts expiring by the end of 2001.
A primary objective of energy-price hedging is to protect product sales from
adverse changes in energy prices. The Company does not enter into hedging
contracts for speculative purposes.
35
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. Common shares of Nextel Communications, XO Communications and
ParkerVision represented the Company's primary investments. At December 31,
2000, the Company holdings amounted to 803,000 shares of Nextel, 214,000
shares of ParkerVision and 237,000 shares of XO.
CREDIT RISK.
The Company's primary market areas are the Rocky Mountain regions of the
United States and Canada and the Midcontinent region of the United States.
Exposure to credit risk may be impacted by the concentration of customers in
these regions due to changes in economic or other conditions. Customers
include individuals and numerous industries that may be affected differently
by changing conditions. Management believes that its credit-review
procedures, loss reserves, customer deposits and collection procedures have
adequately provided for usual and customary credit-related losses.
Commodity-based hedging arrangements also expose the Company to credit risk.
The Company monitors the creditworthiness of its counterparties, which
generally are major financial institutions, and believes that losses from
non-performance are unlikely to occur.
Note 6 - Income Taxes (Restated)
Details of Questar's income tax expenses and deferred income taxes are
provided in the following tables. The components of income taxes were as
follows:
YEAR ENDED DECEMBER 31,
2000 1999 1998
--------------------------------------------
(IN THOUSANDS)
Federal
Current $24,758 $43,326 $39,454
Deferred 47,098 (2,745) (4,094)
State
Current 4,067 6,602 3,918
Deferred 801 776 505
Deferred investment tax credits (386) (387) (387)
Foreign income taxes 2,101 (885) (3,349)
--------------------------------------------
$78,439 $46,687 $36,047
============================================
36
The difference between income tax expense reported and the tax computed by
applying the statutory federal income tax rate of 35% to income before income
taxes is explained as follows:
YEAR ENDED DECEMBER 31,
2000 1999 1998
------------------------------------------
(IN THOUSANDS)
Income before income taxes $227,916 $143,539 $125,357
==========================================
Federal income taxes at 35% $79,771 $50,239 $43,875
State income taxes, net of federal income
tax benefit 3,107 4,789 2,505
Nonconventional fuel credits (6,453) (7,154) (7,953)
Investment tax credits utilized (386) (387) (387)
Deferred taxes related to regulated assets
that were not provided in prior years 921 921 922
Tax benefits from dividends paid to ESOP (398) (840)
Foreign income taxes 723 (189) (964)
Other 756 (1,134) (1,111)
------------------------------------------
Income tax expense $78,439 $46,687 $36,047
==========================================
Effective income tax rate 34.4% 32.5% 28.8%
Significant components of the Company's deferred income taxes were as follows:
DECEMBER 31,
2000 1999
--------------------------
(IN THOUSANDS)
Deferred tax liabilities
Property, plant and equipment $227,633 $193,041
Mark-to-market adjustments of securities
available for sale 8,568 24,333
Other 9,977 13,557
--------------------------
Total deferred tax liabilities 246,178 230,931
Deferred tax assets
Associated with write-down
of investment in partnership 11,806 18,706
Alternative minimum tax and nonconventional-
fuel-credit carryforwards 3 2,468
Deferred compensation 7,443 4,910
Depletion and ITC carryforwards 1,995 2,140
Other 11,795 13,693
--------------------------
Total deferred tax assets 33,042 41,917
--------------------------
Deferred income taxes - noncurrent $213,136 $189,014
==========================
Deferred income taxes - current
Purchased -gas adjustment $13,515 $164
==========================
Cash paid for income taxes was $54,088,000, $35,244,000 and $35,036,000 in
2000, 1999 and 1998, respectively.
37
Note 7 - Litigation and Commitments
BRIDENSTINE VS. KAISER-FRANCIS OIL COMPANY
On January 4, 2001, a district court judge in Texas County, Oklahoma,
approved the settlement agreement reached by the Questar defendants and Union
Pacific Resources Company, predecessor in interest to Questar Exploration &
Production (QE&P), as defendants in the Bridenstine case. Under the terms of
the settlement, the Company and Union Pacific Resources paid a total of $22.5
million ($16.5 million by the Company) to resolve all of the issues in the
litigation. The Questar defendants disputed plaintiffs' claims, but settled
the lawsuit to avoid the uncertainty of a jury verdict. Payment of the
settlement funds did not have a material adverse effect on the Company's
results of operations, financial position, or liquidity.
TRANSCOLORADO CASE
Questar TransColorado Inc. (QTC) and its partner, KN TransColorado, Inc.,
(KNTC) in the TransColorado Gas Transmission Company (TransColorado) are
involved in a complex lawsuit that is pending in a state district court in
Colorado. At the center of the lawsuit is the validity of a contractual right
claimed by QTC to put its 50% interest in TransColorado to KNTC during the
12-month period beginning March 31, 2001.
KNTC originally filed a lawsuit in June of 2000 alleging that Questar
Pipeline and its affiliates breached their fiduciary duties to TransColorado
and KNTC by developing a plan to construct and operate a new pipeline that
would compete with TransColorado, rendering TransColorado economically
unviable. KNTC is seeking damages in excess of $150 million plus punitive
damages; a declaratory judgment that KNTC's obligation to purchase QTC's
interest in the project be declared void and unforceable; and a dissolution
of the partnership under Colorado law. QTC and its affiliates subsequently
filed a counterclaim and third-party complaint against KNTC and named
affiliates, including Kinder Morgan, Inc., seeking a declaratory judgment
that its contractual right to exercise the put is binding and enforceable and
damages of at least $185 million.
The trial judge denied the motion filed by the Questar defendants to stay the
proceedings and remove some issues to be considered by the FERC. The parties
have entered into a standstill agreement that preserves the claims made by
Questar and by KNTC pending the resolution of the litigation. On December 31,
2000, QTC gave notice of its election to exercise its contractual right to
sell its 50% interest in TransColorado to KNTC. The parties have agreed to
hire an outside party to operate the TransColorado pipeline during the
pending litigation. The trial is scheduled for February of 2002.
GRYNBERG LAWSUITS
Questar affiliates are named defendants in a lawsuit filed by independent gas
producer Jack J. Grynberg under the Federal False Claims Act. This case and
the 75 substantially similar cases filed by Grynberg against pipelines and
their affiliates have been consolidated for discovery and pre-trial rulings
in Wyoming federal district court. The cases involve allegations of industry
wide mismeasurement and undervaluation of gas on which royalty payments are
due the federal government. The complaint seeks treble damages and imposition
of civil penalties. The Wyoming district court judge has not ruled on the
defendants' motion to dismiss.
Grynberg has filed a case against Questar Pipeline, Questar Energy Trading
and Questar Gas Management in Utah state district court, alleging
mismeasurement of gas volumes attributable to his working ownership interest
in a specified property in southwestern Wyoming. Grynberg alleges breach of
contract, negligent misrepresentation, fraud, breach of fiduciary duty, etc.
On March 13, 2001, the trial judge granted defendants' motion to dismiss a
case by Grynberg.
It is too early to estimate the outcome of the other cases filed by Grynberg
against Questar affiliates.
There are various other legal proceedings against Questar and its
subsidiaries. While it is not currently possible to predict or determine the
outcomes of these proceedings, it is the opinion of management that the
outcomes will not have a materially adverse effect on the Company's results
of operations, financial position or liquidity.
38
COMMITMENTS
Historically, 45% to 50% of Questar Gas's gas-supply portfolio has been
provided from company-owned gas reserves at the cost of service. The
remainder of the gas supply has been purchased from various suppliers under
agreements with a duration of one year or less and index-based pricing.
Generally, at the conclusion of the heating season and after a bid process,
new agreements for the upcoming heating season are put into place. Questar
Gas bought significant quantities of natural gas under purchase agreements
amounting to $184 million, $93 million and $100 million in 2000, 1999 and
1998, respectively. In addition, Questar Gas makes use of various storage
arrangements to meet peak-gas demand during certain times of the heating
season.
Questar Energy Trading has contracted for firm-transportation services with
various pipelines to transport 76.2 Mdths per day of gas. The contracts
extend for the next six years and have an annual cost of approximately $3
million. Due to market conditions and competition, it is possible that
Questar Energy Trading may be unable to sell enough gas to fully utilize the
contracted capacity.
Questar sold its headquarters building under a sale and lease-back
arrangement in November 1998. The operating agreement commits the Company to
occupy the building for the next 11 years with an option for renewal. The
minimum future payments under the terms of long-term operating leases for the
Company's primary office locations, including its headquarters building, for
the five years following December 31, 2000, are as follows:
(IN THOUSANDS)
2001 $4,507
2002 4,314
2003 4,155
2004 3,677
2005 3,633
Thereafter 37,121
Total minimum future rental payments have not been reduced for sublease
rental receipts of $187,000, and $24,000, which are expected to be received
in the years ended December 31, 2001, and 2002, respectively. Total rental
expense amounted to $4,402,000 in 2000, $4,321,000 in 1999 and $563,000 in
1998. Sublease rental receipts were $96,000 in 2000 and $94,000 in 1999.
Note 8 - Rate Regulation and Other Matters
STATE RATE REGULATION
On August 11, 2000, the Public Service Commission of Utah (PSCU) issued an
order in the general rate case filed by Questar Gas. The PSCU granted $13.5
million in general rate relief and authorized an 11% return on equity. The
$13.5 million in general rate relief includes the $7.1 million in interim
rate relief that Questar Gas was authorized to collect, subject to refund,
effective January 1, 2000. The PSCU's order allows Questar Gas to collect $5
million of carbon-dioxide-processing costs yearly.
In February 2000, the Public Service Commission of Wyoming (PSCW) reaffirmed
Questar Gas's 11.83% authorized return on equity in a general rate case
filing and approved the request for a $377,000 rate reduction. Cost
efficiencies and slower population growth in Wyoming compared with Utah,
enabled Questar Gas to reduce its rates in Wyoming. The PSCW's rate-ruling
also ordered the Company to transfer the recovery of carbon dioxide gas
processing costs from gas costs to general rates beginning April 2000.
Questar Gas routinely files semi-annual applications with the PSCU and the
PSCW requesting permission to reflect annualized gas cost increases or
decreases depending on gas prices. These requests for gas cost increases or
decreases are passed on to customers on a dollar-for-dollar basis with no
markup.
39
On May 31, 2000, Questar Gas filed with the PSCW to reflect annualized gas
costs of $11.1 million in rates for Wyoming customers. The filing reflected a
$53,000 increase from the previous filing. The PSCW authorized Questar Gas to
reflect the request in rates effective July 1, 2000. On June 14, 2000,
Questar Gas filed a request with the PSCU to reflect annualized gas costs of
$286.6 million in rates for Utah customers effective July 1, 2000. The
request slightly decreased rates for residential and commercial customers.
However, the PSCU, by an interim order, chose to make no adjustment in rates.
Due to the rapidly rising gas prices caused by a high demand for energy,
Questar Gas filed an out-of-period pass-on application on September 19, 2000,
with the PSCW seeking approval to reflect an increase of annualized gas costs
of $2.5 million in rates for Wyoming customers. The PSCW authorized the
requested gas-cost increase in rates effective October 1, 2000. On September
20, 2000, Questar Gas filed a special pass-through application with the PSCU
requesting permission to reflect annualized gas cost increases of $63.5
million in rates for Utah customers. The PSCU, by interim order, authorized
Questar Gas to reflect the increase in rates effective October 1, 2000.
As a result of a continuing growing demand for energy and the accompanying
pressure on energy prices, Questar Gas filed on December 19, 2000, with the
PSCU to reflect a $167.5 million increase of annualized gas cost in rates for
Utah customers. The PSCU, by interim order, authorized Questar Gas to reflect
the increase in rates effective January 1, 2001. On December 19, 2000,
Questar Gas filed an application with the PSCW to increase gas costs in
Wyoming rates by $7.1 million. The PSCW authorized the increase in Wyoming
gas rates effective January 1, 2001.
FEDERAL RATE REGULATION
The Federal Energy Regulatory Commission (FERC) issued a final order granting
a certificate of public convenience and necessity to Questar's Southern
Trails Pipeline. The FERC's July 28, 2000, ruling came after the agency
became satisfied that the pipeline was in the public convenience and
necessity and could be completed in an environmentally sound manner. The
California State Lands Commission has formally certified the Environmental
Impact Report for the Southern Trails Pipeline. Questar Pipeline is actively
working on right-of-way issues and exploring marketing opportunities to
subscribe Southern Trail's pipeline capacity.
Questar Pipeline has received a preliminary determination from the FERC to
construct a 75-mile natural gas pipeline from the Price area in eastern Utah
to a proposed interconnect with Kern River Gas Transmission Co. near Elberta,
Utah. A final order is contingent upon completion of an environmental impact
statement. The proposed expansion of Questar Pipeline's interstate system
will parallel an existing Questar pipeline for 57 miles from Price to Payson,
Utah. The $80 million project, referred to as Main Line 104, will be 24
inches in diameter, with a maximum operating pressure of 1,400 pounds per
square inch.
Note 9 - Employee Benefits
Pension Plan: The Company has a defined-benefit pension plan covering the
majority of its employees. Benefits are generally based on the employee's age
at retirement, years of service and highest earnings in a consecutive 72
pay-period interval during the ten years preceding retirement. The Company's
policy is to make contributions to the plan at least sufficient to meet the
minimum funding requirements of the Internal Revenue Code. Plan assets
consist principally of equity securities and corporate and U.S. government
debt obligations.
The Company offered early retirement windows to specific groups of employees
in 2000, 1999 and 1998. Questar's Regulated Services has offered early
retirement windows to eligible employees in 2000 and 1998. In 2000, a total
of 276 employees and recipients of long-term disability from Questar Gas,
Questar Pipeline and Questar Regulated Services elected to retire effective
October 31. The $14.4 million cost of the early retirement window will be
amortized over a five-year period in accordance with regulatory treatment. In
1998, Regulated Services offered an early retirement window that was accepted
by 178 eligible employees. The $3.1 million cost of the window is being
amortized over a five-year period beginning August 1998.
40
Questar InfoComm, which conducts telecommunications and
information-technology services, announced an early retirement program
effective November 1, 1999. Fifty employees elected to retire and the $2.9
million cost was expensed in 1999.
A summary of pension expense is as follows:
YEAR ENDED DECEMBER 31,
2000 1999 1998
------------------------------------------
(IN THOUSANDS)
Service cost $7,354 $8,894 $7,746
Interest cost 18,447 18,814 18,617
Expected return on plan assets (23,782) (24,059) (23,016)
Prior service and other costs 1,581 1,365 872
Recognized net actuarial gain (552)
Early retirement expenses 1,340 3,744 530
------------------------------------------
Pension expense $4,388 $8,758 $4,749
==========================================
Assumptions used to calculate pension expense were as follows:
2000 1999 1998
------------------------------------------
Discount rate 7.75% 6.75% 6.75%
Rate of increase in compensation 5.00% 5.00% 5.00%
Long-term return on assets 9.25% 9.25% 8.50%
The status of the pension plan was as follows:
Pension Plan 2000 1999
--------------------------
(IN THOUSANDS)
Change in benefit obligation
Projected benefit obligation at January 1, $246,958 $252,799
Service cost 7,354 8,894
Interest cost 18,447 18,814
Plan amendments 8,153 2,164
Change in discount rate assumption (42,321)
Actuarial loss 34,096 35,264
Benefits paid (11,275) (11,469)
Early retirement settlements paid (80,946) (17,187)
--------------------------
Projected benefit obligation at December 31, 222,787 246,958
--------------------------
Change in plan assets
Fair value of plan assets at January 1, 274,907 264,632
Actual return on plan assets 4,284 32,831
Contributions to the plan 3,000 6,100
Benefits paid (11,275) (11,469)
Early retirement settlements paid (80,946) (17,187)
--------------------------
Fair value of plan assets at December 31, 189,970 274,907
--------------------------
Plan assets less the projected
benefit obligation (32,817) 27,949
Unrecognized net actuarial (gain) loss 3,053 (36,724)
Unrecognized prior-service cost 19,138 12,424
Unrecognized transition obligation 67 210
--------------------------
(Current liability) prepaid pension expense ($10,559) $3,859
==========================
41
Postretirement Benefits Other Than Pensions: Postretirement health-care
benefits and life insurance are provided only to employees hired before
January 1, 1997. The Company pays a portion of the costs of health-care
benefits, as determined by an employee's years of service, and limited to
170% of the 1992 contribution. The Company's policy is to fund amounts
allowable for tax deduction under the Internal Revenue Code. Plan assets
consist of equity securities and corporate and U.S. government debt
obligations. The Company is amortizing its transition obligation over a
20-year period, which began in 1992.
Regulated Services accounts for approximately 50% of the postretirement
benefit costs. The impact of postretirement benefit costs on Questar's future
net income will be mitigated by the ability to recover these costs from
customers. The regulatory agencies allow Questar Gas and Questar Pipeline to
recover future costs if the amounts are funded in external trusts.
A summary of the expense of postretirement benefits other than pensions
follows:
YEAR ENDED DECEMBER 31,
2000 1999 1998
--------------------------------------------
(IN THOUSANDS)
Service cost $823 $1,006 $1,138
Interest cost 4,979 4,545 4,094
Expected return on plan assets (3,241) (2,831) (1,830)
Amortization of transition obligation 1,877 1,877 1,878
Amortization of regulatory liability 523
--------------------------------------------
Postretirement-benefit expense $4,438 $5,120 $5,280
============================================
Assumptions used to calculate postretirement benefit expense were as follows:
2000 1999 1998
----------------------------------------------
Discount rate 7.75% 6.75% 6.75%
Long-term return on assets 9.25% 9.25% 8.50%
Health care inflation rate 10.00% 10.50% 11.00%
decreasing to decreasing to decreasing to
6.5% by 2008 5.5% by 2010 5.5% by 2010
A 1% increase in the health-care inflation rate would increase the service
cost and interest cost by $290,000 and the accumulated postretirement benefit
obligation by $3.3 million. A 1% decrease in the health-care inflation rate
would decrease the service cost and interest cost by $210,000 and the
accumulated postretirement benefit obligation by $2.8 million. The status of
the postretirement benefit programs was as follows:
Postretirement Benefits Other Than Pensions
2000 1999
---------------------------
(IN THOUSANDS)
Change in benefit obligation
Projected benefit obligation at January 1, $66,169 $64,245
Service cost 823 1,006
Interest cost 4,979 4,545
Actuarial gain (701) (498)
Benefits paid (3,406) (3,129)
---------------------------
Projected benefit obligation at December 31, 67,864 66,169
---------------------------
42
2000 1999
---------------------------
(IN THOUSANDS)
Change in plan assets
Fair value of plan assets at January 1, 35,302 30,845
Actual return on plan assets 389 3,732
Contributions to the plan 3,017 3,854
Benefits paid (3,406) (3,129)
---------------------------
Fair value of plan assets at December 31, 35,302 35,302
---------------------------
Projected benefit obligation
in excess of plan assets (32,562) (30,867)
Unrecognized transition obligation 22,529 24,406
Unrecognized net gain (2,442) (4,594)
---------------------------
Accrued postretirement benefit
liability recorded in current liabilities ($12,475) ($11,055)
===========================
Postemployment Benefits: The Company recognizes the net present value of the
liability for postemployment benefits, such as long-term disability benefits
and health-care and life-insurance costs, when employees become eligible for
such benefits. Postemployment benefits are paid to former employees after
employment has been terminated but before retirement benefits are paid. The
Company accrues both current and future costs. In 2000, 14 former employees
of Questar Regulated Services and recipients of postemployment benefits
accepted early retirement benefits. Questar's postemployment liability at
December 31, 2000, 1999 and 1998 was $1,381,000, $2,347,000 and $2,452,000,
respectively.
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's utility operations to share in the results of
Wexpro's operations. The agreement was approved by the PSCU and PSCW in 1981
and affirmed by the Supreme Court of Utah in 1983. Major provisions of the
settlement agreement are as follows:
a. Wexpro continues to hold and operate all oil-producing properties previously
transferred from Questar Gas's nonutility accounts. The oil production from
these properties is sold at market prices, with the revenues used to recover
operating expenses and to give Wexpro a return on its investment. The after-tax
rate of return is adjusted annually and is approximately 13.64%. Any net income
remaining after recovery of expenses and Wexpro's return on investment is
divided between Wexpro and Questar Gas, with Wexpro retaining 46%.
b. Wexpro conducts developmental oil drilling on productive oil properties and
bears any costs of dry holes. Oil discovered from these properties is sold at
market prices, with the revenues used to recover operating expenses and to give
Wexpro a return on its investment in successful wells. The after-tax rate of
return is adjusted annually and is approximately 18.64%. Any net income
remaining after recovery of expenses and Wexpro's return on investment is
divided between Wexpro and Questar Gas, with Wexpro retaining 46%.
c. Amounts received by Questar Gas from the sharing of Wexpro's oil income are
used to reduce natural-gas costs to utility customers.
d. Wexpro conducts developmental gas drilling on productive gas properties
and bears any costs of dry holes. Natural gas produced from successful
drilling is owned by Questar Gas. Wexpro is reimbursed for the costs of
producing the gas plus a return on its investment in successful wells. The
after-tax return allowed Wexpro is approximately 21.64%.
e. Wexpro operates natural-gas properties owned by Questar Gas. Wexpro is
reimbursed for its costs of operating these properties, including a rate of
return on any investment it makes. This after-tax rate of return is
approximately 13.64%.
43
Note 11 - Operations by Line of Business (Restated)
Following is a summary of operations by line of business for the Year Ended
December 31.
QUESTAR REGULATED SERVICES
-------------------------------------------------
QUESTAR NATURAL GAS NATURAL GAS OTHER CORPORATE INTERCOMPANY QUESTAR
MARKET DISTRIBUTION TRANSMISSION & OTHER TRANSACTIONS CONSOLIDATED
RESOURCES OPERATIONS
---------------------------------------------------------------------------------------------
(IN THOUSANDS)
2000
Revenues
From unaffiliated customers $649,200 $531,988 $42,500 $3,642 $38,823 $1,266,153
From affiliated companies 92,853 4,774 76,576 283 34,586 ($209,072)
---------------------------------------------------------------------------------------------
742,053 536,762 119,076 3,925 73,409 (209,072) 1,266,153
Operating expenses
Cost of natural gas and
other products sold 369,752 334,193 2,253 24,640 (168,609) 562,229
Operating and maintenance 106,761 101,486 43,761 1,668 33,506 (35,705) 251,477
Exploration 7,917 7,917
Depreciation, depletion and
amortization 85,025 34,450 15,391 35 7,590 142,491
Abandonment and impairment
of oil and gas properties 3,418 3,418
Other expenses 41,020 10,213 3,071 35 1,073 (4,758) 50,654
---------------------------------------------------------------------------------------------
Total operating expenses 613,893 480,342 62,223 3,991 66,809 (209,072) 1,018,186
---------------------------------------------------------------------------------------------
Operating income (loss) 128,160 56,420 56,853 (66) 6,600 247,967
Interest and other income 8,412 1,673 3,025 1,349 36,926 (11,922) 39,463
Income from unconsol. Affiliates 2,776 1,220 3,996
Debt expense (22,922) (21,041) (17,584) (722) (13,163) 11,922 (63,510)
Income tax expense (38,618) (12,889) (13,689) (217) (13,026) (78,439)
---------------------------------------------------------------------------------------------
Net income $77,808 $24,163 $29,825 $344 $17,337 $149,477
=============================================================================================
Identifiable assets $960,491 $830,889 $538,408 $19,640 $122,599 $2,472,027
Investment in unconsol. affiliates 15,417 19,088 34,505
Capital expenditures 187,359 65,767 43,035 1,167 17,814 315,142
1999
Revenues
From unaffiliated customers $418,603 $447,606 $36,922 $2,260 $18,828 $924,219
From affiliated companies 79,708 2,331 75,238 196 38,851 ($196,324)
---------------------------------------------------------------------------------------------
498,311 449,937 112,160 2,456 57,679 (196,324) 924,219
Operating expenses
Cost of natural gas and
other products sold 239,201 257,265 774 9,651 (154,337) 352,554
Operating and maintenance 79,719 103,308 38,534 1,700 37,516 (39,695) 221,082
Exploration 5,321 5,321
Depreciation, depletion and
amortization 73,028 36,426 16,743 14 5,953 132,164
Abandonment and impairment
of oil and gas properties 7,535 7,535
Other expenses 23,808 7,625 2,488 24 1,071 (2,292) 32,724
---------------------------------------------------------------------------------------------
Total operating expenses 428,612 404,624 57,765 2,512 54,191 (196,324) 751,380
---------------------------------------------------------------------------------------------
Operating income (loss) 69,699 45,313 54,395 (56) 3,488 172,839
Interest and other income 8,272 2,980 4,229 1,014 73,406 (11,201) 78,700
Income (loss) from
unconsol. affiliates 763 (5,109) (10) (4,356)
Write-down of investment
in partnership (49,700) (49,700)
Debt expense (17,363) (20,062) (17,466) (605) (9,649) 11,201 (53,944)
Income tax (expense) credit (17,483) (9,012) 5,260 (102) (25,350) (46,687)
---------------------------------------------------------------------------------------------
Net income (loss) $43,888 $19,219 ($8,391) $251 $41,885 $96,852
=============================================================================================
44
QUESTAR REGULATED SERVICES
-------------------------------------------------
QUESTAR NATURAL GAS NATURAL GAS OTHER CORPORATE INTERCOMPANY QUESTAR
MARKET DISTRIBUTION TRANSMISSION & OTHER TRANSACTIONS CONSOLIDATED
RESOURCES OPERATIONS
---------------------------------------------------------------------------------------------
(IN THOUSANDS)
Identifiable assets $777,923 $722,290 $517,981 $11,423 $155,117 $2,184,734
Investment in unconsol. affiliates 13,301 11,724 244 25,269
Capital expenditures 128,248 68,447 50,424 1,385 13,479 261,983
1998
Revenues
From unaffiliated customers $382,791 $475,754 $37,156 $2,355 $8,200 $906,256
From affiliated companies 75,481 1,069 71,401 99 39,707 ($187,757)
---------------------------------------------------------------------------------------------
458,272 476,823 108,557 2,454 47,907 (187,757) 906,256
Operating expenses
Cost of natural gas and
other products sold 230,462 281,004 1,249 1,515 (146,298) 367,932
Operating and maintenance 73,460 96,923 38,832 2,269 37,113 (40,406) 208,191
Exploration 6,069 6,069
Depreciation, depletion and
amortization 64,965 33,261 13,927 17 6,575 118,745
Abandonment and impairment
of oil and gas properties 15,137 15,137
Other expenses 26,041 8,185 2,600 1,019 (1,053) 36,792
---------------------------------------------------------------------------------------------
Total operating expenses 416,134 419,373 55,359 3,535 46,222 (187,757) 752,866
---------------------------------------------------------------------------------------------
Operating income (loss) 42,138 57,450 53,198 (1,081) 1,685 153,390
Interest and other income 2,457 3,566 78 655 22,756 (12,491) 17,021
Income (loss) from
unconsolidated affiliates (930) 4,011 (164) 2,917
Debt expense (12,631) (19,792) (14,456) (385) (13,198) 12,491 (47,971)
Income tax (expense) credit (4,886) (13,816) (14,940) 339 (2,744) (36,047)
---------------------------------------------------------------------------------------------
Net income (loss) $26,148 $27,408 $27,891 ($472) $8,335 $89,310
=============================================================================================
Identifiable assets $728,953 $699,727 $556,226 $8,519 $118,115 $2,111,540
Investment in unconsol. affiliates 3,673 54,712 253 58,638
Capital expenditures 248,676 76,328 114,318 493 15,662 455,477
Questar Market Resources has subsidiaries that conducts gas and oil exploration
and production activities in western Canada. Canadian operations reported
revenues, measured in U. S. dollars, totaling $38.1 million, $12.3 million and
$10.5 million for the 12 months ended December 31, 2000, 1999, and 1998,
respectively. Total assets at December 31, stated in U. S. dollars, amounted to
$103.9 million, $31.0 million and $30.3 million in 2000, 1999 and 1998,
respectively.
45
Note 12 - Quarterly Financial and Stock Price Information (Unaudited)
Following is a summary of quarterly financial and stock price data.
(Restated)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER YEAR
---------------------------------------------------------------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2000
Revenues $336,702 $232,542 $245,117 $451,792 $1,266,153
Operating income 78,653 41,240 43,521 84,553 247,967
Net income 48,568 24,155 26,406 50,348 149,477
Basic earnings per common share 0.60 0.30 0.33 0.63 1.86
Diluted earnings per common share 0.60 0.30 0.33 0.62 1.85
Dividends per common share 0.17 0.17 0.17 0.175 0.685
Market price per common share
High $19.00 $20.63 $28.00 $31.88 $31.88
Low $13.56 $17.13 $18.88 $26.00 $13.56
Close $18.56 $19.38 $27.81 $30.06 $30.06
Price-earnings ratio on closing price 16.3
Annualized dividend yield on closing price 3.7% 3.5% 2.4% 2.3% 2.3%
Market-to-book ratio on closing price 2.55
Average number of common shares traded per day 233 169 237 280 230
1999
Revenues $277,814 $177,858 $183,070 $285,477 $924,219
Operating income 66,691 30,402 27,346 48,400 172,839
Net income 42,926 22,966 15,051 15,909 96,852
Basic earnings per common share 0.52 0.28 0.18 0.19 1.17
Diluted earnings per common share 0.52 0.28 0.18 0.19 1.17
Dividends per common share 0.165 0.165 0.17 0.17 0.67
Market price per common share
High $19.38 $19.94 $19.63 $19.13 $19.94
Low $16.13 $15.81 $17.88 $14.75 $14.75
Close $16.94 $19.13 $18.13 $15.00 $15.00
Price-earnings ratio on closing price 12.8
Annualized dividend yield on closing price 3.9% 3.5% 3.8% 4.5% 4.5%
Market-to-book ratio on closing price 1.36
Average number of common shares traded per day 201 147 138 179 166
1998
Revenues $300,083 $179,157 $150,282 $276,734 $906,256
Operating income 68,590 25,724 18,604 40,472 153,390
Net income 41,797 16,578 8,492 22,443 89,310
Basic earnings per common share 0.51 0.20 0.10 0.27 1.08
Diluted earnings per common share 0.50 0.20 0.10 0.27 1.08
Dividends per common share 0.1575 0.165 0.165 0.165 0.6525
Market price per common share
High $22.28 $22.38 $19.81 $20.38 $22.38
Low $20.19 $18.69 $15.81 $17.38 $15.19
Close $20.78 $19.63 $19.25 $19.38 $19.38
Price-earnings ratio on closing price 17.9
Annualized dividend yield on closing price 3.2% 3.4% 3.4% 3.4% 3.4%
Market-to-book ratio on closing price 1.89
Average number of common shares traded per day 171 165 169 188 173
46
Note 13 - Supplemental Oil and Gas Information (Unaudited)
THE COMPANY USES THE SUCCESSFUL EFFORTS ACCOUNTING METHOD FOR ITS OIL AND GAS
EXPLORATION AND DEVELOPMENT activities. As ordered by the Public Service
Commission of Utah, the successful efforts method of accounting is utilized
with respect to costs associated with certain cost-of-service 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 Questar's oil and gas exploration and development
activities, located in the United States and Canada.
CAPITALIZED COSTS (RESTATED)
The aggregate amounts of costs capitalized for oil and gas exploration and
development activities and the related amounts of accumulated depreciation
and amortization follow:
-----------------------------------------------------------
AS OF DECEMBER 31, UNITED STATES CANADA TOTAL
-----------------------------------------------------------
(IN THOUSANDS)
2000
Proved properties $732,078 $113,407 $845,485
Unproved properties 30,940 24,668 55,608
Support equipment and facilities 12,002 1,177 13,179
-----------------------------------------------------------
775,020 139,252 914,272
Accumulated depreciation, depletion and amortization 361,401 50,105 411,506
-----------------------------------------------------------
$413,619 $89,147 $502,766
===========================================================
1999
Proved properties $663,051 $54,096 $717,147
Unproved properties 41,654 9,970 51,624
Support equipment and facilities 12,418 990 13,408
-----------------------------------------------------------
717,123 65,056 782,179
Accumulated depreciation, depletion and amortization 314,986 38,413 353,399
-----------------------------------------------------------
$402,137 $26,643 $428,780
===========================================================
1998
Proved properties $656,085 $47,069 $703,154
Unproved properties 34,736 11,478 46,214
Support equipment and facilities 13,949 929 14,878
-----------------------------------------------------------
704,770 59,476 764,246
Accumulated depreciation, depletion and amortization 284,252 32,849 317,101
-----------------------------------------------------------
$420,518 $26,627 $447,145
===========================================================
47
COSTS INCURRED (RESTATED)
The following costs were incurred in oil and gas exploration and development
activities:
---------------------------------------------------
YEAR ENDED DECEMBER 31, UNITED STATES CANADA TOTAL
---------------------------------------------------
(IN THOUSANDS)
2000
Property acquisition
Unproved $3,054 $14,703 $17,757
Proved 1,202 31,058 32,260
Exploration 6,433 3,664 10,097
Development 64,582 29,478 94,060
---------------------------------------------------
$75,271 $78,903 $154,174
===================================================
1999
Property acquisition
Unproved $12,565 $337 $12,902
Proved 2,367 17 2,384
Exploration 8,402 323 8,725
Development 53,347 3,608 56,955
---------------------------------------------------
$76,681 $4,285 $80,966
===================================================
1998
Property acquisition
Unproved $29,343 $144 $29,487
Proved 126,723 3,131 129,854
Exploration 10,187 2,122 12,309
Development 42,875 4,477 47,352
---------------------------------------------------
$209,128 $9,874 $219,002
===================================================
RESULTS OF OPERATIONS (RESTATED)
Following are the results of operations of Market Resources' oil and gas
exploration and development activities, before corporate overhead and interest
expenses. In 1998, oil and gas properties were written down due to lower energy
prices.
---------------------------------------------------
UNITED
STATES CANADA TOTAL
---------------------------------------------------
YEAR ENDED DECEMBER 31, 2000 (IN THOUSANDS)
Revenues
From unaffiliated customers $207,656 $38,072 $245,728
From affiliates 18 18
---------------------------------------------------
Total revenues 207,674 38,072 245,746
---------------------------------------------------
Production expenses 49,116 9,370 58,486
Exploration 5,533 2,442 7,975
Depreciation, depletion and amortization 51,973 13,196 65,169
Abandonment and impairment of oil
and gas properties 2,327 1,091 3,418
---------------------------------------------------
Total expenses 108,949 26,099 135,048
---------------------------------------------------
Revenues less expenses 98,725 11,973 110,698
Income taxes - Note A 31,972 5,580 37,552
---------------------------------------------------
Results of operations before corporate
overhead and interest expenses $66,753 $6,393 $73,146
===================================================
48
YEAR ENDED DECEMBER 31, 1999
Revenues $150,159 $12,316 $162,475
---------------------------------------------------
Production expenses 41,948 3,681 45,629
Exploration 4,803 321 5,124
Depreciation, depletion and amortization 51,927 3,550 55,477
Abandonment and impairment of oil
and gas properties 5,542 1,993 7,535
---------------------------------------------------
Total expenses 104,220 9,545 113,765
---------------------------------------------------
Revenues less expenses 45,939 2,771 48,710
Income taxes - Note A 12,313 1,233 13,546
---------------------------------------------------
Results of operations before corporate
overhead and interest expenses $33,626 $1,538 $35,164
===================================================
YEAR ENDED DECEMBER 31, 1998
Revenues $125,035 $10,474 $135,509
---------------------------------------------------
Production expenses 38,788 3,004 41,792
Exploration 4,434 1,332 5,766
Depreciation, depletion and amortization 45,301 3,302 48,603
Abandonment and impairment of oil
and gas properties 10,045 5,092 15,137
---------------------------------------------------
Total expenses 98,568 12,730 111,298
---------------------------------------------------
Revenues less expenses 26,467 (2,256) 24,211
Income taxes - Note A 5,514 (896) 4,618
---------------------------------------------------
Results of operations before corporate
overhead and interest expenses $20,953 ($1,360) $19,593
===================================================
Note A - Income tax expenses has been reduced by nonconventional fuel tax
credits of $4,655,000 in 2000, $5,282,000 in 1999 and $5,736,000 in 1998.
49
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
Estimates of the reserves located in the United States were made by Ryder Scott
Company, H. J. Gruy and Associates, Inc., Netherland, Sewell & Associates, and
Malkewicz Hueni Associates, Inc., independent reservoir engineers. Estimated
Canadian reserves were prepared by Gilbert Laustsen Jung Associates Ltd. and
Sproule Associates Ltd. Reserve estimates are based on a complex and highly
interpretive process that is subject to continuous revision as additional
production and development-drilling information becomes available. The
quantities reported below are based on existing economic and operating
conditions at December 31. All oil and gas reserves reported were located in the
United States and Canada. The Company does not have any long-term supply
contracts with foreign governments or reserves of equity investees.
NATURAL GAS OIL
UNITED STATES CANADA TOTAL UNITED STATES CANADA TOTAL
---------------------------------------------------------------------------------------------
(MMcf) (MBbls)
PROVED RESERVES
Balance at January 1, 1998 357,529 21,134 378,663 12,664 2,435 15,099
Revisions of estimates 378 (3,568) (3,190) (3,165) 238 (2,927)
Extensions and discoveries 28,598 1,984 30,582 442 261 703
Purchase of reserves in place 129,207 5,110 134,317 3,720 71 3,791
Sale of reserves in place (440) (440) (76) (76)
Production (48,584) (2,725) (51,309) (1,936) (404) (2,340)
---------------------------------------------------------------------------------------------
Balance at December 31, 1998 466,688 21,935 488,623 11,649 2,601 14,250
Revisions of estimates 4,155 (106) 4,049 4,031 372 4,403
Extensions and discoveries 77,737 1,720 79,457 794 257 1,051
Purchase of reserves in place 17,020 17,020 130 130
Sale of reserves in place (11,984) (11,984) (3,665) (3,665)
Production (59,839) (2,873) (62,712) (1,876) (435) (2,311)
---------------------------------------------------------------------------------------------
Balance at December 31, 1999 493,777 20,676 514,453 11,063 2,795 13,858
Revisions of estimates 25,662 (7,890) 17,772 221 (64) 157
Extensions and discoveries 123,155 2,511 125,666 1,532 208 1,740
Purchase of reserves in place 846 52,000 52,846 1 1,520 1,521
Sale of reserves in place (1,885) (1,885) (17) 0 (17)
Production (61,722) (7,241) (68,963) (1,484) (741) (2,225)
---------------------------------------------------------------------------------------------
Balance at December 31, 2000 579,833 60,056 639,889 11,316 3,718 15,034
=============================================================================================
PROVED-DEVELOPED RESERVES
Balance at January 1, 1998 300,550 16,670 317,220 10,769 1,851 12,620
Balance at December 31, 1998 411,826 17,835 429,661 10,443 2,281 12,724
Balance at December 31, 1999 412,008 17,076 429,084 9,897 2,565 12,462
Balance at December 31, 2000 434,122 55,623 489,745 9,696 3,077 12,773
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES
(RESTATED)
Future net cash flows were calculated at December 31 using year-end prices
and known contract-price changes. The year-end prices do not include any
impact of hedging activities. Year-end production costs, development costs
and appropriate statutory income tax rates, with consideration of future tax
rates already legislated, were used to compute the future net cash flows. All
cash flows were discounted at 10% to reflect the time value of cash flows,
without regard to the risk of specific properties.
50
The assumptions used to derive the standardized measure of future net cash
flows are those required by accounting standards and do not necessarily
reflect the Company's expectations. The usefulness of the standardized
measure of future net cash flows is impaired because of the reliance on
reserve estimates and production schedules that are inherently imprecise.
YEAR ENDED DECEMBER 31, UNITED STATES CANADA TOTAL
-----------------------------------------------
(IN THOUSANDS)
2000
Future cash inflows $5,412,945 $568,771 $5,981,716
Future production costs (955,827) (73,583) (1,029,410)
Future development costs (107,355) (2,900) (110,255)
Future income tax expenses (1,489,267) (182,537) (1,671,804)
-----------------------------------------------
Future net cash flows 2,860,496 309,751 3,170,247
10% annual discount to reflect
timing of net cash flows (1,316,114) (136,445) (1,452,559)
-----------------------------------------------
Standardized measure of discounted
future net cash flows $1,544,382 $173,306 $1,717,688
===============================================
1999
Future cash inflows $1,332,761 $108,990 $1,441,751
Future production costs (398,591) (28,280) (426,871)
Future development costs (61,034) (3,146) (64,180)
Future income tax expenses (188,988) (10,353) (199,341)
-----------------------------------------------
Future net cash flows 684,148 67,211 751,359
10% annual discount to reflect
timing of net cash flows (280,911) (23,652) (304,563)
-----------------------------------------------
Standardized measure of discounted
future net cash flows $403,237 $43,559 $446,796
===============================================
1998
Future cash inflows $982,404 $66,885 $1,049,289
Future production costs (320,355) (22,088) (342,443)
Future development costs (45,138) (696) (45,834)
Future income tax expenses (84,868) (84,868)
-----------------------------------------------
Future net cash flows 532,043 44,101 576,144
10% annual discount to reflect
timing of net cash flows (212,959) (14,809) (227,768)
-----------------------------------------------
Standardized measure of discounted
future net cash flows $319,084 $29,292 $348,376
===============================================
51
The principal sources of change in the standardized measure of discounted future
net cash flows were:
YEAR ENDED DECEMBER 31,
2000 1999 1998
-------------------------------------------
(IN THOUSANDS)
Beginning balance $446,796 $348,376 $300,994
Sales of oil and gas produced, net
of production costs (187,260) (116,846) (93,717)
Net changes in prices and
production costs 1,637,549 171,392 (53,613)
Extensions and discoveries, less
related costs 492,398 79,511 24,120
Revisions of quantity estimates 70,155 28,665 (14,399)
Purchase of reserves in place 32,260 2,384 129,854
Sale of reserves in place (1,867) (33,043) (540)
Accretion of discount 44,680 34,837 30,099
Net change in income taxes (776,276) (61,807) 5,632
Change in production rate (50,077) (8,859) 6,728
Other 9,330 2,186 13,218
-------------------------------------------
Net change 1,270,892 98,420 47,382
-------------------------------------------
Ending balance $1,717,688 $446,796 $348,376
===========================================
COST-OF-SERVICE ACTIVITIES
The following information is provided with respect to cost-of-service oil and
gas properties managed and developed by Wexpro and regulated by the Wexpro
settlement agreement. Information on the standardized measure of future net
cash flows has not been included for cost-of-service activities because the
operations of and return on investment for such properties are regulated by
the Wexpro settlement agreement.
CAPITALIZED COSTS
Capitalized costs for cost-of-service oil and gas properties net of the
related accumulated depreciation and amortization were as follows:
DECEMBER 31,
2000 1999 1998
----------------------------------------
(IN THOUSANDS)
Wexpro $155,374 $137,584 $129,573
Questar Gas 22,620 25,380 27,739
----------------------------------------
$177,994 $162,964 $157,312
========================================
COSTS INCURRED
Costs incurred by Wexpro for cost of service oil and gas producing activities
were $32,066,000 in 2000, $21,273,000 in 1999 and $26,956,000 in 1998.
52
RESULTS OF OPERATIONS
Following are the results of operations of the Company's cost-of-service gas
and oil development activities before corporate overhead and interest
expenses.
YEAR ENDED DECEMBER 31,
2000 1999 1998
-------------------------------------------
(IN THOUSANDS)
Revenues
From unaffiliated companies $15,179 $8,844 $10,025
From affiliates - Note A 73,721 62,335 58,581
-------------------------------------------
Total revenues 88,900 71,179 68,606
Production expenses 27,861 18,548 22,439
Depreciation and amortization 13,922 12,665 11,379
-------------------------------------------
Total expenses 41,783 31,213 33,818
-------------------------------------------
Revenues less expenses 47,117 39,966 34,788
Income taxes 16,923 14,602 12,441
-------------------------------------------
Results of operations before corporate
overhead and interest expenses $30,194 $25,364 $22,347
===========================================
Note A - Represents revenues received from Questar Gas pursuant to Wexpro
Settlement Agreement.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
The following estimates were made by the Company's reservoir engineers. No
estimates are available for cost of service proved-undeveloped reserves that may
exist.
NATURAL GAS OIL
----------------------------
(MMcf) (MBbls)
PROVED DEVELOPED RESERVES
Balance at January 1, 1998 337,179 3,049
Revisions of estimates 15,017 (46)
Extensions and discoveries 25,077 333
Production (37,138) (613)
----------------------------
Balance at December 31, 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
Revisions of estimates 16,523 504
Extensions and discoveries 50,351 234
Production (41,546) (579)
----------------------------
Balance at December 31, 2000 379,011 3,448
=============================
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized, on
the day of January 16, 2002.
QUESTAR CORPORATION
(Registrant)
By /s/ R. D. Cash
----------------------------------------
R. D. Cash
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
/s/ R. D. Cash Chairman and Chief Executive
--------------------------- Officer (Principal Executive
R. D. Cash Officer)
/s/ S. E. Parks Senior Vice President, Treasurer and
--------------------------- Chief Financial Officer (Principal
S. E. Parks Financial and Accounting Officer)
*R. D. Cash Director
*K. O. Rattie Director
*Teresa Beck Director
*Patrick J. Early Director
*W. W. Hawkins Director
*Robert E. Kadlec Director
*Dixie L. Leavitt Director
*Gary G. Michael Director
*G. L. Nordloh Director
*Scott S. Parker Director
*D. N. Rose Director
*Harris H. Simmons Director
JANUARY 16, 2002 *By /s/ R. D. Cash
----------------------- --------------------------------
Date R. D. Cash, Attorney in Fact
55