1
CONSOLIDATED SELECTED FINANCIAL STATISTICS 21
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Year Ended December 31, 1998 1997 1996 1995 1994
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(Thousands of dollars, except per share amounts)
Operating revenues............... $ 917,309 $ 732,010 $ 644,061 $ 563,502 $ 599,553
Operating expenses............... 763,139 629,749 572,488 505,090 510,863
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Operating income................. $ 154,170 $ 102,261 $ 71,573 $ 58,412 $ 88,690
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Income from continuing
operations..................... $ 47,537 $ 16,469 $ 6,574 $ 2,654 $ 23,524
Income (loss) from discontinued
operations, net of tax()1...... -- -- -- (17,536) 2,777
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Net income (loss)................ $ 47,537 $ 16,469 $ 6,574 $ (14,882) $ 26,301
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Net income (loss) applicable to
common stock................... $ 47,537 $ 16,469 $ 6,574 $ (15,189) $ 25,791
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Total assets at year end......... $1,830,694 $1,769,059 $1,560,269 $1,532,527 $1,453,582
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Capitalization at year end
Common equity.................. $ 476,400 $ 385,979 $ 379,616 $ 356,050 $ 348,556
Preferred stocks............... -- -- -- -- 4,000
Trust originated preferred
securities................... 60,000 60,000 60,000 60,000 --
Long-term debt................. 812,906 778,693 665,221 607,945 678,263
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$1,349,306 $1,224,672 $1,104,837 $1,023,995 $1,030,819
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Common stock data
Return on average common
equity....................... 11.0% 4.3% 1.8% (4.1)% 7.6%
Basic earnings (loss) per share
Continuing operations........ $ 1.66 $ 0.61 $ 0.25 $ 0.10 $ 1.09
Discontinued operations...... -- -- -- (0.76) 0.13
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Basic earnings (loss) per
share........................ $ 1.66 $ 0.61 $ 0.25 $ (0.66) $ 1.22
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Diluted earnings (loss) per
share........................ $ 1.65 $ 0.61 $ 0.25 $ (0.66) $ 1.22
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Dividends paid per share....... $ 0.82 $ 0.82 $ 0.82 $ 0.82 $ 0.80
Payout ratio................... 49% N/A N/A N/A 66%
Book value per share at year
end.......................... $ 15.67 $ 14.09 $ 14.20 $ 14.55 $ 16.38
Market value per share at year
end.......................... $ 26.63 $ 18.69 $ 19.25 $ 17.63 $ 14.13
Market value per share to book
value per share.............. 170% 133% 136% 121% 86%
Common shares outstanding at
year end (000)............... 30,410 27,387 26,733 24,467 21,282
Number of common shareholders
at year end.................. 24,489 25,833 26,371 25,133 20,765
Ratio of earnings to fixed
charges
Continuing operations.......... 2.08 1.28 1.15 1.06 1.69
Adjusted for interest allocated
to discontinued operations... 2.08 1.28 1.15 1.05 1.61
1. Contribution from the financial services segment, including the 1995 loss on
sale of the Bank.
2
22 NATURAL GAS OPERATIONS
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Year Ended December 31, 1998 1997 1996 1995 1994
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(Thousands of dollars)
Sales............................ $ 753,338 $ 569,542 $ 506,200 $ 524,914 $ 560,207
Transportation................... 46,259 45,123 40,161 38,588 39,061
Other............................ -- -- -- -- 285
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Operating revenue................ 799,597 614,665 546,361 563,502 599,553
Net cost of gas sold............. 329,849 209,338 187,580 227,456 249,922
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Operating margin................. 469,748 405,327 358,781 336,046 349,631
Expenses
Operations and maintenance..... 209,172 201,159 198,364 187,969 178,310
Depreciation and
amortization................. 80,231 74,528 67,443 62,492 57,284
Other.......................... 31,646 29,393 28,156 27,173 25,347
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Operating income................. $ 148,699 $ 100,247 $ 64,818 $ 58,412 $ 88,690
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Contribution to consolidated net
income (loss).................. $ 44,830 $ 15,825 $ 3,919 $ 2,654 $ 23,524
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Total assets at year end......... $1,772,418 $1,717,025 $1,498,099 $1,357,034 $1,277,727
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Net gas plant at year end........ $1,459,362 $1,360,294 $1,278,457 $1,137,750 $1,035,916
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Construction expenditures and
property additions............. $ 179,361 $ 164,528 $ 210,743 $ 166,183 $ 141,390
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Cash flow, net
From operating activities...... $ 189,465 $ 45,923 $ 47,931 $ 97,754 $ 84,074
From investing activities...... (176,731) (170,455) (41,804) (163,718) (141,547)
From financing activities...... (12,632) 132,349 (11,456) 71,056 61,422
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Net change in cash............... $ 102 $ 7,817 $ (5,329) $ 5,092 $ 3,949
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Total throughput (thousands of
therms)
Sales.......................... 1,103,264 914,732 818,329 805,884 881,868
Transportation................. 1,001,372 1,030,857 968,208 1,016,011 914,791
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Total throughput................. 2,104,636 1,945,589 1,786,537 1,821,895 1,796,659
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Weighted average cost of gas
purchased ($/therm)............ $ 0.27 $ 0.35 $ 0.27 $ 0.21 $ 0.30
Customers at year end............ 1,209,000 1,151,000 1,092,000 1,029,000 980,000
Employees at year end............ 2,429 2,447 2,420 2,383 2,359
Degree days -- actual............ 2,321 1,976 1,896 1,781 2,091
Degree days -- ten-year
average........................ 2,043 2,022 2,033 2,021 2,068
3
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of Southwest Gas Corporation and subsidiaries (the
Company) includes information related to its regulated natural gas transmission
and distribution activities and nonregulated activities. In 1996, the Company
completed the sale of PriMerit Bank, Federal Savings Bank (the Bank), which was
reported as discontinued operations. The loss on disposition was included in the
1995 results of operations.
The Company is principally engaged in the business of purchasing,
transporting, and distributing natural gas (Southwest or natural gas operations
segment). Southwest is the largest distributor in Arizona, selling and
transporting natural gas in most of southern, central, and northwestern Arizona,
including the Phoenix and Tucson metropolitan areas. Southwest is also the
largest distributor and transporter of natural gas in Nevada, and serves the Las
Vegas metropolitan area and northern Nevada. In addition, Southwest distributes
and transports natural gas in portions of California, including the Lake Tahoe
area in northern California and high desert and mountain areas in San Bernardino
County.
As of December 31, 1998 Southwest had 1,209,000 residential, commercial,
industrial, and other customers, of which 689,000 customers were located in
Arizona, 403,000 in Nevada, and 117,000 in California. Residential and
commercial customers represented over 99 percent of the total customer base.
During 1998, Southwest added 58,000 customers, a five percent increase, of which
28,000 customers were added in Arizona, 28,000 in Nevada, and 2,000 in
California. Customer growth over the past three years averaged over five percent
annually. These additions are largely attributed to population growth in the
service areas. Based on current commitments from builders, customer growth is
expected to approximate five percent in 1999. During 1998, 57 percent of
operating margin was earned in Arizona, 33 percent in Nevada, and 10 percent in
California. During this same period, Southwest earned 84 percent of operating
margin from residential and small commercial customers, 5 percent from other
sales customers, and 11 percent from transportation customers. These patterns
are similar to prior years and are expected to continue.
In April 1996, the Company acquired all of the outstanding stock of
Northern Pipeline Construction Co. (Northern or construction services segment)
pursuant to a definitive agreement dated November 1995. The Company issued
approximately 1,439,000 shares of common stock valued at $24 million in
connection with the acquisition. The acquisition was accounted for as a
purchase. Goodwill in the amount of approximately $10 million was recorded by
Northern and is being amortized over 25 years. Northern provides utility
companies with trenching and installation, replacement, and maintenance services
for energy distribution systems.
23
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In December 1998, the Boards of Directors of the Company and ONEOK, Inc.
(ONEOK), headquartered in Tulsa, Oklahoma, announced a definitive agreement for
the Company to be merged into ONEOK. The agreement calls for ONEOK to pay cash
of $28.50 for each share of Company common stock outstanding. The transaction is
subject to customary conditions, including approvals from shareholders of the
Company and state regulators in Arizona, California, and Nevada. ONEOK expects
to account for the merger using the purchase method of accounting. If the merger
is consummated, the Company would operate as a division of ONEOK.
In connection with the proposed merger into ONEOK, the Company incurred
approximately $1.1 million (pretax) of financial advisor and legal costs, which
were included in Other income (deductions), net, during the fourth quarter of
1998. Additional amounts of financial advisor, legal, and accounting-related
expenses will be incurred during the merger process and, depending on the
successful completion of the merger, are estimated at $2 million to $5 million.
In February 1999, the Company announced that it had received an unsolicited
proposal from Southern Union Company (Southern Union), headquartered in Austin,
Texas, offering to acquire the Company for $32.00 per share in cash. The
proposal is preliminary in nature and subject to a number of contingencies and
uncertainties. Under the terms of the agreement with ONEOK, as a result of
certain preliminary determinations made by the Board of Directors of the
Company, the Board of Directors has authorized management to commence
substantive discussions with Southern Union regarding its proposal. No
assurances can be given that any agreement will be reached with Southern Union.
The merger agreement with ONEOK remains in full force and effect.
CAPITAL RESOURCES AND LIQUIDITY
The capital requirements and resources of the Company generally are
determined independently for the natural gas operations and construction
services segments. Each business activity is generally responsible for securing
its own financing sources. The capital requirements and resources of the
construction services segment are not material to the overall capital
requirements and resources of the Company.
Southwest continues to experience significant population growth throughout
its service territories. This growth has required large amounts of capital to
finance the investment in infrastructure, in the form of new transmission and
distribution plant, to satisfy consumer demand. For example, during the
three-year period ended December 31, 1998, total gas plant increased from $1.6
billion to $2 billion, or at an annual rate of nine percent.
During 1998, capital expenditures were $179 million. Approximately 75
percent of these current-period expenditures represented new construction and
the balance represented costs associated with routine replacement of existing
transmission, distribution, and general plant. Cash flows from operating
activities of Southwest (net of dividends) provided $166 million of the required
capital resources pertaining to these construction expenditures. The remainder
was provided from net external financing activities. The improvement in
operating cash flows from expected levels was due to higher earnings and timing
differences principally associated with deferred purchased gas cost recoveries
and income taxes.
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Southwest estimates construction expenditures during the three-year period
ending December 31, 2001 will be approximately $580 million. During the
three-year period, cash flow from operating activities (net of dividends) is
estimated to fund approximately 60 percent of the gas operations total
construction expenditures. A portion of the construction expenditure funding
will be provided by $20 million of funds held in trust, at December 31, 1998,
from the issuance of industrial development revenue bonds (IDRB). The remaining
cash requirements are expected to be provided by external financing sources. The
timing, types, and amounts of these additional external financings will be
dependent on a number of factors, including conditions in the capital markets,
timing and amounts of rate relief, growth levels in Southwest service areas, and
merger-related developments (see Note 13 of the Notes to Consolidated Financial
Statements). These external financings may include the issuance of both debt and
equity securities, bank and other short-term borrowings, and other forms of
financing. Under the definitive agreement with ONEOK, common stock issuances are
currently limited to those necessary under employee benefit and dividend
reinvestment plans.
Liquidity refers to the ability of an enterprise to generate adequate
amounts of cash to meet its cash requirements. General factors that could
significantly affect capital resources and liquidity in future years include
inflation, growth in the economy, changes in income tax laws, changes in the
ratemaking policies of regulatory commissions, interest rates, and the level of
natural gas prices.
The rate schedules in all of the service territories of Southwest contain
purchased gas adjustment (PGA) clauses which permit adjustments to rates as the
cost of purchased gas changes. Southwest must first obtain regulatory approval
before changing the rates it charges for recovery of gas costs. The PGA
mechanism allows Southwest to change the gas cost component of the rates charged
to its customers to reflect increases or decreases in the price expected to be
paid to its suppliers and companies providing interstate pipeline transportation
service. In addition, Southwest uses this mechanism to either refund amounts
over-collected or recoup amounts under-collected as compared to the price paid
for natural gas during the period since the last PGA rate change went into
effect. Generally, tariffs for Southwest provide for annual adjustment dates for
changes in purchased gas costs. In addition, Southwest may request to adjust
rates more often than once each year, if conditions warrant. These changes
impact cash flows but have no direct impact on profit margin. See RATES AND
REGULATORY PROCEEDINGS for details of these filings.
The Company has established a common stock dividend policy which states
that common stock dividends will be paid at a prudent level that is within the
normal dividend payout range for its respective businesses, and that the
dividend will be established at a level considered sustainable in order to
minimize business risk and maintain a strong capital structure throughout all
economic cycles. The quarterly common stock dividend was 20.5 cents per share
throughout 1998.
Securities ratings issued by nationally recognized ratings agencies provide
a method for determining the credit worthiness of an issuer. Company debt
ratings are important because long-term debt constitutes a significant portion
of total capitalization. These debt ratings are a factor considered by lenders
when determining the cost of debt for the Company (i.e., the better the rating,
the lower the cost to borrow funds).
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Since January 1997, Moody's Investor Service has rated Company unsecured
long-term debt at Baa2. Moody's debt ratings range from Aaa (best quality) to C
(lowest quality). Moody's applies a Baa2 rating to obligations which are
considered medium grade obligations (i.e., they are neither highly protected nor
poorly secured).
Since September 1997, Duff & Phelps Credit Rating Co. has rated Company
unsecured long-term debt at BBB. Duff & Phelps debt ratings range from AAA
(highest rating possible) to DD (defaulted debt obligation). The Duff & Phelps
rating of BBB indicates a credit quality that is considered prudent for
investment.
The Company's unsecured long-term debt rating from Standard and Poor's
(S&P) is BBB-. S&P debt ratings range from AAA (highest rating possible) to D
(obligation is in default). The S&P rating of BBB- indicates the debt is
regarded as having an adequate capacity to pay interest and repay principal.
A securities rating is not a recommendation to buy, sell, or hold a
security and is subject to change or withdrawal at any time by the rating
agency.
The impact of inflation on results of operations has diminished in recent
years. Natural gas, labor, and construction costs are the categories most
significantly impacted by inflation. Changes to Company cost of gas are
generally recovered through PGA mechanisms and do not significantly impact net
earnings when approved as filed. Labor is a component of the cost of service,
and construction costs are the primary component of rate base. In order to
recover increased costs, and earn a fair return on rate base, general rate cases
are filed by Southwest, when deemed necessary, for review and approval by its
regulatory authorities. Regulatory lag, that is, the time between the date
increased costs are incurred and the time such increases are recovered through
the ratemaking process, can impact earnings. See RATES AND REGULATORY
PROCEEDINGS for discussion of recent rate case proceedings.
CONSOLIDATED RESULTS OF OPERATIONS
CONTRIBUTION TO NET INCOME
Year Ended December 31, 1998 1997 1996
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(Thousands of dollars)
Natural gas operations...................................... $44,830 $15,825 $3,919
Construction services....................................... 2,707 644 2,655
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Net income.................................................. $47,537 $16,469 $6,574
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1998 VS. 1997 Earnings per share for the year ended December 31, 1998 were
$1.66, a $1.05 increase from per share earnings of $0.61 recorded for the year
ended December 31, 1997. Current-year earnings were composed of $1.57 per share
from natural gas operations and $0.09 per share from construction services.
Prior-year results included the impact of three nonrecurring events which
reduced earnings by $4.1 million, or $0.15 per share. Average shares outstanding
increased by 1.5 million shares between years, primarily resulting from a 2.5
million share common stock issuance in August 1998.
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1997 VS. 1996 Earnings per share for the year ended December 31, 1997 were
$0.61, a $0.36 increase from per share earnings of $0.25 recorded for the year
ended December 31, 1996. The 1997 earnings were composed of $0.59 per share from
natural gas operations and $0.02 per share from construction services. Average
shares outstanding increased by 1.2 million shares between years, primarily
resulting from continuing issuances under the Dividend Reinvestment and Stock
Purchase Plan.
RESULTS OF NATURAL GAS OPERATIONS
Year Ended December 31, 1998 1997 1996
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(Thousands of dollars)
Gas operating revenues...................................... $799,597 $614,665 $546,361
Net cost of gas sold........................................ 329,849 209,338 187,580
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Operating margin.......................................... 469,748 405,327 358,781
Operations and maintenance expense.......................... 209,172 201,159 198,364
Depreciation and amortization............................... 80,231 74,528 67,443
Taxes other than income taxes............................... 31,646 29,393 28,156
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Operating income.......................................... 148,699 100,247 64,818
Other income (deductions), net.............................. (2,115) (12,979) (760)
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Income before interest and income taxes................... 146,584 87,268 64,058
Net interest deductions..................................... 62,284 61,751 53,003
Preferred securities distributions.......................... 5,475 5,475 5,475
Income tax expense.......................................... 33,995 4,217 1,661
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Contribution to consolidated net income................... $ 44,830 $ 15,825 $ 3,919
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1998 VS. 1997 The gas segment contribution to consolidated net income increased
$29 million from 1997. The increase was the result of record first quarter
earnings driven by cooler temperatures, rate relief, and customer growth. The
second and third quarters were substantially better than the prior year,
primarily as a result of customer growth, second quarter weather, and rate
design improvements. Fourth quarter results were about the same as the prior
year.
Operating margin increased $64 million, or 16 percent, in 1998. Arizona
rate relief, effective September 1997, contributed $23 million towards the
increase. Customer growth accounted for $16 million as Southwest added 58,000
customers during the year, a five percent increase. The remaining $25 million
was due to differences in heating demand caused by weather variations between
periods.
Operations and maintenance expenses increased $8 million, or four percent,
reflecting increases in labor and other costs, including the incremental
expenses associated with meeting the needs of a growing customer base.
Depreciation expense and general taxes increased $8 million, or eight
percent, as a result of construction activities. Average gas plant in service
increased $136 million, or eight percent, compared to the prior year. This was
attributed to the upgrade of existing operating facilities and the expansion of
the system to accommodate customer growth.
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Net interest deductions increased less than one percent between years.
Stronger-than-expected cash flows from operating activities, coupled with a 2.5
million share common stock offering, reduced the need to issue net new debt
during the year.
Other income (deductions), net improved $10.9 million. Prior year results
included two nonrecurring charges recorded in the fourth quarter (see discussion
below). In connection with the proposed merger into ONEOK, the Company incurred
approximately $1.1 million (pretax) of financial advisor and legal costs, which
were included in other income (deductions), net, during the fourth quarter of
1998. Additional amounts of financial advisor, legal, and accounting-related
costs will be incurred during the merger process. See Note 13 of the Notes to
Consolidated Financial Statements for additional disclosures related to the
proposed merger.
1997 VS. 1996 The gas segment contribution to consolidated net income increased
$11.9 million from 1996. The increase was the result of fundamental improvements
in operating margin coupled with more favorable weather conditions.
Operating margin increased $47 million, or 13 percent, due to customer
growth, rate relief, and the return to more normal winter season temperatures
following consecutive years of record-setting warm weather. Rate relief in
Arizona and Nevada accounted for approximately $20 million of the operating
margin increase. Colder-than-normal weather during the fourth quarter of 1997
partially offset the effects of first quarter warmer-than-normal temperatures
and, overall, weather-related factors resulted in $19 million of additional
operating margin. During 1997, Southwest added 59,000 customers, a five percent
increase, contributing $8 million towards the change in operating margin.
Depreciation expense and general taxes increased $8.3 million, or nine
percent, as a result of construction activities in 1997. Average gas plant in
service increased $162 million, or ten percent, during this same period. This
was attributed to the upgrade of existing operating facilities and the expansion
of the system to accommodate customer growth.
Net interest deductions during 1997 increased $8.7 million, or 17 percent,
from 1996. Average total debt outstanding during this period increased due to
the financing of construction expenditures and working capital needs and
included higher short-term debt, the issuance of medium-term notes during 1997,
and the drawdown of IDRB funds held in trust. The increase in short-term debt
reflected the need for short-term financing to cover higher gas costs
experienced during the 1996/1997 winter heating season.
During the fourth quarter of 1997, Southwest recognized nonrecurring
charges to income related to cost overruns on two separate construction
projects. These charges are reflected in other income (deductions), net. An $8
million nonrecurring pretax charge resulted from cost overruns experienced
during expansion of the northern California service territory. A second pretax
charge, for $5 million, related to cost overruns on a nonutility construction
project. A subsidiary of the Company was building a liquefied natural gas (LNG)
storage and distribution system to serve several small towns. The project was
completed in 1998. See Note 11 of the Notes to Consolidated Financial Statements
for additional disclosures related to these projects. Partially offsetting these
charges was the recognition of a $3.4 million income tax benefit related to the
successful settlement
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in November 1997 of open tax issues dating back as far as 1988. The combined
impact of these three nonrecurring events was a $4.1 million, or $0.15 per
share, after-tax reduction to earnings.
RATES AND REGULATORY PROCEEDINGS
CALIFORNIA GENERAL RATE CASES. Southwest last filed general rate applications
for its California jurisdictions with the California Public Utilities Commission
(CPUC) in 1994. Increased rates went into effect in January 1995 and continued
through 1998 as part of a settlement agreement. In addition, annual operational
attrition increases have been received in northern California. However,
primarily as a result of the northern California expansion proposal described
below, the Company filed a petition with the CPUC in March 1999 requesting an
extension of the rate case cycle. Approval of this petition would result in a
general rate moratorium through December 2000 at a minimum.
NEVADA GENERAL RATE CASES. In December 1995, Southwest filed general rate cases
for its northern and southern Nevada jurisdictions. Increased rates went into
effect in July 1996 as part of a settlement agreement. The settlement agreement
also specified a moratorium on future general rate increase requests until April
1999.
ARIZONA GENERAL RATE CASE. In November 1996, Southwest filed its most recent
general rate application with the Arizona Corporation Commission (ACC) seeking
approval to increase revenues for both Arizona rate jurisdictions. In August
1997, the ACC approved a settlement of the general rate case providing the
Company with a $32 million annualized general rate increase effective September
1997. There is no rate moratorium in Arizona on future general rate filings.
FERC GENERAL RATE CASE. In July 1996, Paiute Pipeline Company, a wholly owned
subsidiary of the Company, filed a general rate case with the Federal Energy
Regulatory Commission (FERC) seeking approval to increase rates. Effective
January 1997, the FERC authorized a $3.2 million annualized general rate
increase. The settlement prohibits Paiute from filing for a rate increase until
December 1999.
NORTHERN CALIFORNIA EXPANSION PROJECT. In December 1993, Southwest filed an
application with the CPUC to expand its northern California service territory
and extend service into Truckee, California. The application included a proposed
regulatory mechanism for recovering the cost of the expansion. In May 1994, rate
and cost recovery issues related to the expansion application were combined by
the CPUC with a January 1994 general rate application Southwest had filed with
the CPUC. In September 1994, a Joint Motion and Stipulation and Settlement
Agreement (Settlement) was presented to the CPUC which resolved the general rate
case and addressed the expansion related cost recovery issues. In December 1994,
the Settlement was approved. In April 1995, Southwest received CPUC approval for
the certificate of public convenience and necessity to serve the expansion
areas.
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In its filing, Southwest had indicated that expansion into Truckee would
occur in three phases and result in the conversion of an estimated 9,200
customers to natural gas service from their existing fuel, primarily propane.
The CPUC established a cost cap of $29.1 million for the project.
In 1995, Southwest completed Phase I of the expansion project, which
involved transmission system reinforcement and distribution system expansion to
accommodate approximately 940 customers. Construction costs of $7.1 million were
on target with the cost estimate approved by the CPUC.
Phase II of the project involved extending the transmission system to
Truckee and expanding the distribution system to accommodate an estimated 4,200
customers. The cost cap apportioned to Phase II was approximately $13.8 million.
The incurred cost of Phase II was $28.8 million. An estimated $9.2 million of
the Phase II cost overrun was due to changes in project scope, such as
adjustments for design changes required by governmental bodies, changes in
facilities necessitated by requirements beyond Southwest's control, and costs
incurred to accommodate customer service requests.
Examples of adjustments for changes in project scope included the
requirement to haul excavated soil off-site to be screened whereas normal and
anticipated practice is to screen on-site, asphalt repairs which were greater
than expected due to increased paving requirements imposed after construction
started, and the installation of more facilities under asphalt than anticipated.
Other unexpected or externally imposed costs pertained to extended yard lines,
underground boring, environmental studies, right-of-way acquisitions, and
engineering design work.
Due to the Phase II cost overruns and difficult construction environment
experienced, construction of Phase III was postponed to reevaluate the economics
of completing the project.
In July 1997, Southwest filed an application requesting authorization from
the CPUC to modify the terms and conditions of the certificate of public
convenience and necessity granted in 1995. In this application, Southwest
requested that the originally approved cost cap of $29.1 million be increased to
$46.8 million; that the scope of Phase III construction be revised to include
only an estimated 2,900 of the initially estimated 4,200 customers; and that
customer applicants desiring service in the expansion area who were not
identified to receive service during the expansion phases as modified within the
new application be subject to the existing main and service extension rules.
Southwest proposed to recover the incremental costs above the original cost cap
through a surcharge mechanism. Concurrently, the Truckee town manager, on behalf
of the Truckee Town Council, wrote a letter to the CPUC in support of the
application.
The areas requested to be excluded from the revised scope of Phase III are
the most distant points from existing mains and present some of the most
challenging geographic conditions in the expansion area. Extension of mains to
serve the estimated 1,300 customers in the excluded areas would be considerably
more expensive than the service areas in Phases I and II. Furthermore, these
areas have significantly lower customer density than the remainder of the
expansion project; therefore, expected revenues would be insufficient to justify
the anticipated construction costs.
In August 1997, the Office of Ratepayer Advocates (ORA) for the CPUC filed
a protest to the Southwest application indicating that the terms of the original
agreement should be adhered to. Southwest responded with written comments in
support of its application. In September 1997, a prehearing conference was held
to discuss the filing, the ORA protest, and Southwest comments.
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The administrative law judge (ALJ) made a preliminary ruling in favor of the ORA
protest, but allowed the parties an additional 20 days to supplement their
comments. During this time, Southwest and the ORA, pursuant to direction from
the CPUC, began to negotiate a settlement agreement, and the procedural schedule
was adjusted to allow the negotiations to continue beyond the 20-day period.
In January 1998, a settlement involving all parties to the proceeding was
executed and filed with the CPUC which redefined the terms and conditions for
completing the project and recovering the additional project costs. Although
CPUC approval of the settlement was still required, management anticipated
approval of the all-party settlement. In February 1998, a prehearing conference
was held before the ALJ and the assigned Commissioner for the purpose of taking
public comment on the settlement agreement. There was no opposition to the
settlement agreement from the Truckee Town Council at the conference, or in a
letter written by the Truckee town manager to the CPUC subsequent to the
conference.
Under the January 1998 proposed settlement, Southwest agreed, among other
things, to absorb $8 million in cost overruns experienced in Phase II of the
project. Southwest also agreed to an $11 million cost cap (with a maximum of
$3,800 per customer) for Phase III of the project. The Phase III project scope
would be modified as requested in the July 1997 application. In addition,
Southwest agreed not to file its next general rate case until the completion of
Phase III. Based on the proposed settlement, Southwest recognized an $8 million
pretax charge in the fourth quarter of 1997.
In May 1998, the ALJ issued an unexpected Proposed Decision (PD) rejecting
the January 1998 all-party settlement and directing Southwest to complete the
project under the terms and conditions of the 1995 certificate. A PD that
ignores an all-party settlement is rare and inconsistent with CPUC policies and
procedures established in 1992. Subsequent to the PD, the Truckee Town Council
took a formal position in opposition to the settlement, although they were not a
party to the proceeding, and had not previously opposed the settlement.
In July 1998, the CPUC voted to adopt the PD and reject the all-party
settlement, and ordered Southwest to proceed with all deliberate speed to
complete the project under the terms and scope of the 1995 certificate.
Southwest filed a Motion for Stay (Motion) of order and petitioned the CPUC for
rehearing (Petition) in August 1998. The CPUC stated in its order that Southwest
was required to show extraordinary circumstances to readjudicate the original
settlement. Because no evidentiary hearings were conducted, management did not
have the opportunity to demonstrate that such extraordinary circumstances exist;
however, it believes that such circumstances do exist. In September 1998, the
CPUC denied the Motion and in January 1999, the Petition was denied. As a
result, in February 1999, Southwest petitioned the Supreme Court of the State of
California for review of the July 1998 CPUC decision. Such a petition is
discretionary with the Supreme Court, and if accepted, could take up to two
years to be heard.
In September 1998, Southwest filed a civil lawsuit in the United States
Federal District Court naming the Town of Truckee as a defendant for an
indeterminate amount of damages. Southwest asserts that actions taken by the
Town of Truckee resulted in unanticipated changes in project
12
32
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scope, which materially contributed to the cost overruns experienced during the
construction of Phase II of the project.
In November 1998, Southwest, together with representatives from the town of
Truckee, met before a federal mediator to reconcile the disputes and claims
against each other. As a result of the mediation, Southwest and representatives
of the town of Truckee are attempting to negotiate a Settlement Agreement and
Mutual Release (Agreement). If an Agreement is reached, it would need to be
ratified by the Truckee Town Council and approved by the CPUC, and likely would
address the civil suit against the town of Truckee, the remaining project scope,
and recovery of project costs among other items. An Agreement might also require
Southwest to postpone the filing of its next California general rate case. If an
Agreement is reached, it is anticipated that it will be presented to the Truckee
Town Council at a town meeting. If ratified by the Truckee Town Council,
Southwest would include the Agreement as part of a new application it plans to
file with the CPUC to reopen the prior California general rate case and
certificate proceeding in order to modify the original Settlement approved in
December 1994.
Management believes that subsequent events may reduce the remaining scope
and estimated costs of the project; however, preliminary estimates indicate that
it could cost an additional $23 million to $25 million to complete the project
under the terms of the 1995 certificate without modification. An additional
pretax write-off of up to $24 million could be recorded under this scenario.
This estimate is comprised of approximately $7 million related to costs incurred
through Phase II, and up to $17 million for the forecasted construction costs.
However, Southwest will actively pursue the described regulatory and legal
proceedings with the intent of reversing or mitigating the effects of the July
1998 CPUC action. Management believes that a reasonable possibility of modifying
the existing CPUC orders pertaining to the expansion project exists through
pursuit of the legal and regulatory remedies that have been outlined, although
there can be no assurance of a favorable outcome. As a result, Southwest has not
recorded any additional write-offs beyond the $8 million recognized in the
fourth quarter of 1997. Management also believes that civil litigation offers a
reasonable possibility of recovering certain amounts spent to deal with changes
in scope necessitated by unanticipated third party actions.
PGA FILINGS
The following table shows the most recent PGA changes authorized by rate
jurisdiction (thousands of dollars):
Annualized
Revenue Effective
Jurisdiction Adjustment Percentage Date
- --------------------------------------------------------------------------------------------------
Arizona:
Central and Southern $46,900 14% April 1998
California:
Northern 2,600 19 January 1998
Southern 10,000 19 December 1997
Nevada:
Northern (782) (1) November 1998
Southern (3,000) (2) November 1998
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ARIZONA PGA FILING. In March 1998, the ACC approved a purchased gas adjustment
(PGA) filing submitted by Southwest in January 1998 to recover deferred
purchased gas costs in Arizona. This filing, which became effective in April
1998, resulted in an annual revenue increase of $46.9 million, or 14 percent.
The increase in rates was designed to recover the accumulated PGA balance
related to Arizona customers, and to eliminate the refunds previously built into
the rate structure. PGA changes impact cash flows but have no direct impact on
profit margin.
In October 1998, the ACC approved a proposal by the ACC staff, to modify
the methodology used by Arizona natural gas utilities in calculating and
revising customer rates to reflect changes in the cost of gas. The
modifications, which will become effective in June 1999, will use a twelve-month
rolling average of the commodity cost of gas and related transportation costs.
The updated rates will be reflected in customer bills each month. The changes
are designed to reduce volatility on customer bills and in the PGA balance. The
mechanism also provides for recovery from customers of the existing balance in
the deferred purchased gas cost account.
NEVADA PGA FILING. In January 1997, Southwest submitted an out-of-period PGA
filing in Nevada in response to a substantial run-up in the commodity cost of
natural gas during November and December of 1996. In September 1997, the Public
Utilities Commission of Nevada (PUCN) approved the filing providing annual
increases of $10.1 million, or nine percent, in the southern Nevada rate
jurisdiction, and $6 million, or 14 percent, in the northern Nevada rate
jurisdiction.
In June 1997, Southwest submitted its annual PGA filing in compliance with
the Nevada Gas Tariff. The filing covered the period from April 1996 through
March 1997. Southwest requested annual increases of $23.1 million, or 18
percent, in the southern Nevada rate jurisdiction, and $8.4 million, or 17
percent, in the northern Nevada rate jurisdiction.
In an order issued in December 1997, the PUCN found that "Southwest failed
to mitigate the risk inherent in a portfolio of all indexed-priced contracts and
failed to reasonably quantify the costs of any risk mitigation." As a result,
gas costs of $3.8 million in southern Nevada and $1.8 million in northern Nevada
were disallowed. The approved annualized revenue increase, after consideration
of the amounts disallowed, was $17.3 million, or 14 percent in southern Nevada,
and $5.2 million, or 11 percent in northern Nevada.
In December 1997, Southwest filed a Petition for Reconsideration (Petition)
of the decision with the PUCN on the grounds that the findings of fact and
conclusions of law are contrary to binding legislative enactments and judicial
decisions. Specifically, the Petition asserted, among other things, that the
PUCN violated its settled obligation in the previous PGA docket, which included
the same winter period, in finding Southwest to be imprudent. Effectively, the
PUCN allowed a previously settled claim to be relitigated. In addition,
management also believes that the PUCN failed to follow its previous rules and
practices surrounding a PGA proceeding, or changed those rules effective with
the disallowance order and sought to retroactively apply them, which would have
required compliance with formal rulemaking procedures mandated by Nevada
Statutes. In February 1998, the PUCN reaffirmed the original order.
In March 1998, Southwest filed a petition for judicial review (appeal) of
the final order of the PUCN with the Nevada District Court (NDC). The appeal
alleged the same procedural irregularities as were included in the Petition. In
November 1998, the NDC issued an order in which the December 1997 order
14
34
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was determined to be void on procedural grounds. Specifically, the decision
found that the Chairman of the PUCN did not have a majority when proceedings
were reopened to accept additional evidence in support of a cost disallowance.
This decision, if not overturned on appeal, has the effect of allowing Southwest
a full recovery of the gas costs requested in the June 1997 PGA filing.
In December 1998, the PUCN filed a motion with the NDC asking for an
amendment or alteration of the November 1998 NDC decision. Oral arguments were
heard in February 1999. The NDC affirmed its prior order in favor of the
Company. The PUCN filed a notice of appeal to the Nevada Supreme Court in
February 1999. No substantive action is expected to take place during 1999.
In June 1998, Southwest submitted its annual PGA filing in compliance with
the Nevada Gas Tariff. Effective November 1998, new rates were approved by the
PUCN. No gas cost disallowances were ordered and no prudency issues were raised.
The new rates, reflecting a lower cost of gas, resulted in annualized revenue
decreases of $3 million, or two percent in the southern Nevada rate
jurisdiction, and $782,000, or one percent in the northern Nevada rate
jurisdiction. These PGA changes impact cash flows but have no direct impact on
profit margin.
RESULTS OF CONSTRUCTION SERVICES
Year Ended December 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of dollars)
Construction revenues....................................... $117,712 $117,345
Cost of construction........................................ 108,911 112,194
- -----------------------------------------------------------------------------------------
Gross profit............................................ 8,801 5,151
General and administrative expenses......................... 2,931 2,777
- -----------------------------------------------------------------------------------------
Income from operations.................................. 5,870 2,374
Other income (expense), net................................. 326 379
- -----------------------------------------------------------------------------------------
Income before interest and income taxes................. 6,196 2,753
Interest expense............................................ 1,070 1,467
Income tax expense.......................................... 2,419 642
- -----------------------------------------------------------------------------------------
Contribution to consolidated net income................. $ 2,707 $ 644
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
1998 VS. 1997 The construction services segment contribution to consolidated net
income increased $2.1 million from 1997. The increase was the result of a
fundamental improvement in gross profit margin coupled with favorable weather
conditions.
With comparable revenues of approximately $117 million, gross profit
increased $3.6 million from 1997. The improvement is attributed to obtaining
more profitable new contracts, eliminating less profitable contracts,
implementing cost containment measures, and favorable winter weather conditions
in several of the cold-climate operating areas during the first and fourth
quarters of 1998.
General and administrative expenses remained relatively constant, while
interest expense decreased approximately $397,000. Timely billings to customers
coupled with collections of accounts receivable and the timing of equipment
purchases had a direct impact in reducing interest costs.
1997 VS. 1996 Contribution to consolidated net income from construction services
was $644,000 in 1997. In 1996, construction services contributed $2.7 million,
however, those results excluded the preacquisition months January through April
which are typically loss months. The decline was primarily
15
35
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a result of lower-than-anticipated revenues caused by various project
cancellations and curtailments in portions of California, Washington, Missouri,
and Kansas. Northern reorganized and closed offices in some of those areas to
pursue new contracts in other areas to improve profitability. Comparative
information by major income statement caption was not provided for 1996 since
those results were for a partial year.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
It requires an entity to recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. SFAS No. 133 also requires that changes in the fair value of
derivative instruments be recognized currently in earnings in the income
statement unless specific hedge accounting criteria are met. Special hedge
accounting for qualified hedges allows changes in the fair value of derivative
instruments to be offset in the income statement in the period in which the
related changes in the fair value of the item being hedged occurs. Hedge
accounting requires an entity to formally document, designate, and assess hedge
effectiveness. This statement is effective for quarters of fiscal years
beginning after June 15, 1999 (i.e., first quarter of 2000). The Company does
not currently utilize stand-alone derivatives for speculative purposes or for
hedging, and does not have foreign currency exposure. However, the Company is
reviewing gas supply and other contracts for potential embedded derivatives that
may need to be recognized and disclosed under the requirements of this complex
statement.
YEAR 2000 READINESS DISCLOSURE
Most companies have computer systems that use two digits to identify a year
in the date field (e.g. "98" for 1998). These systems must be modified to handle
turn-of-the-century calculations. If not corrected, system failures or
miscalculations could occur, potentially causing disruptions of operations,
including, among other things the inability to process transactions, send
invoices, or engage in other normal business activities. The Year 2000 issue
also threatens disruptions in government services, telecommunications, and other
essential industries. This creates potential risk for all companies, even if
their own computer systems are Year 2000 compliant.
In 1994, the Company initiated a comprehensive review of its computer
systems to identify processes that could be adversely affected by Year 2000
issues. By early 1995, the Company identified computer application systems that
required modification or replacement. Since that time, the Company has focused
on converting all business-critical systems to be Year 2000 compliant.
In addition to the evaluation and remediation of computer application
systems and components, the Company has also developed a comprehensive Year 2000
compliance plan. As part of this plan, the Company has formed a Year 2000
project team with the mission of ensuring that all critical systems, facilities,
and processes are identified and analyzed for Year 2000 compliance. The project
team consists of representatives from several strategic departments of the
Company.
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The Year 2000 plan includes specific timetables for categories of tasks for
each department as follows:
(1) Assess Year 2000 issues -- complete;
(2) Analyze, prioritize, and catalog Year 2000 issues -- substantially complete;
(3) Create action plans -- in process and due by the first quarter of 1999;
(4) Implement plans and validate compliance -- in process and due by the third
quarter of 1999.
The Company's top priority is to ensure that natural gas can be received
from suppliers and delivered to customers. To accomplish this, the Company has
sent inquiries to its five major providers of interstate natural gas
transportation service. All of these providers have responded to the inquiries
indicating that they intend to be Year 2000 compliant before the end of 1999.
The Company has also evaluated its gas pipeline delivery systems, which are the
systems used to distribute natural gas from the interstate pipelines to the
customer. These systems utilize an extensive network of hardware and software
devices that schedule, regulate, measure, or otherwise facilitate the flow of
natural gas. Of these devices, approximately 70 percent are Year 2000 compliant,
while approximately 30 percent were determined to be noncompliant or were in the
process of being replaced or remediated. Remediation or replacement of the
noncompliant devices is expected to be completed by the middle of 1999.
Many of the Company's business-critical computer systems are Year 2000
compliant. For example, the customer service system which supports customer
billing, accounts receivable, and other customer service functions is Year 2000
compliant. The general ledger accounting system of the Company is also Year 2000
compliant. Year 2000 compliance work on other systems, such as accounts payable,
purchasing, human resources, and payroll, is in process. In total, approximately
80 percent (including work-in-progress) of the Company's computer applications
are currently Year 2000 compliant. The Company has also assessed its other
computer components, such as computer equipment and software, and determined
that approximately 90 percent of these components are Year 2000 compliant. The
Company projects that both the computer application systems and the other
computer components will be Year 2000 compliant by the third quarter of 1999.
The Company has initiated communications with suppliers and vendors to
determine the extent to which those companies are addressing Year 2000
compliance issues. The Company is requiring business-critical suppliers and
vendors to certify compliance in order to continue doing business with the
Company. In addition, the Company is identifying and contacting alternate
suppliers and vendors as part of a Year 2000 contingency plan. All of the
companies contacted have responded that efforts are underway to become
compliant.
The Company is also assessing and remediating Year 2000 issues related to
embedded system devices (such as microcontrollers used in equipment and
machinery), data exchange functions, networks, telecommunications, security
access and building control systems, forms, reports, and other business
processes and activities. The Company expects these areas to be Year 2000
compliant by the third quarter of 1999.
17
37
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The Company is in the process of developing contingency scenarios for each
district and division. These scenarios will consider the systems, operations,
and devices that have been identified as at risk for failure. These scenarios
will attempt to forecast what failures might occur, where the failures might
occur, as well as the impact of the failures on dependent systems, operations,
and devices. As part of this process, the Company will identify the most
reasonably likely worst case Year 2000 scenario. The Company will then prepare
for this scenario by developing contingency plans for all "high risk" systems,
operations, and devices. This process will culminate in the development of a
"Contingency Plan Operations Guide." This guide will document specific items
associated with the Company's Year 2000 contingency plans including
personnel-related items, non-labor resources required by the plan, command and
decision authority roles, and location and function of a contingency command
center. The Contingency Plan Operations Guide is scheduled for completion during
the third quarter of 1999.
The Company estimates that the cost of remediation will be approximately $2
million. Expenditures of approximately $1 million have already been incurred in
connection with systems that have been converted. The remediation costs include
internal labor costs, as well as fees and expenses paid to outside contractors
specifically associated with reprogramming or replacing noncompliant components.
At the present time, the Company does not expect that such expenditures will
have a material impact on results of operations or financial condition.
The Company's Year 2000 plans, including costs and completion schedules,
are based on management's best estimates. These estimates were derived using
numerous assumptions of future events including, but not limited to, third party
modification plans, availability of qualified personnel, support of software
vendors, and other factors. The Company is also relying on the representations
made by significant third party suppliers and vendors.
FORWARD-LOOKING STATEMENTS
This annual report contains statements which constitute "forward-looking
statements" within the meaning of the Securities Litigation Reform Act of 1995
(Reform Act). All such forward-looking statements are intended to be subject to
the safe harbor protection provided by the Reform Act. A number of important
factors affecting the business and financial results of the Company could cause
actual results to differ materially from those stated in the forward-looking
statements. These factors include, but are not limited to, the impact of weather
variations on customer usage, natural gas prices, the effects of
regulation/deregulation, the timing and amount of rate relief, the outcome of
Southwest's challenges to regulatory actions in California and Nevada, changes
in capital requirements and funding, Year 2000 remediation efforts,
acquisitions, competition, and merger-related developments (see Note 13 of the
Notes to Consolidated Financial Statements).
18
38
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COMMON STOCK PRICE AND DIVIDEND INFORMATION
1998 1997 Dividends Paid
---------------- ---------------- ---------------
High Low High Low 1998 1997
- -------------------------------------------------------------------------------------------------------
First Quarter................................... $21 1/2 $17 5/16 $20 1/4 $17 1/4 $0.205 $0.205
Second Quarter.................................. 25 20 3/8 19 7/8 16 1/8 0.205 0.205
Third Quarter................................... 24 1/2 17 3/8 20 1/8 17 3/4 0.205 0.205
Fourth Quarter.................................. 26 7/8 20 3/16 19 15/1 17 1/8 0.205 0.205
--------------
$0.820 $0.820
--------------
--------------
The principal markets on which the common stock of the Company is traded
are the New York Stock Exchange and the Pacific Stock Exchange. At March 15,
1999 there were 24,186 holders of record of common stock and the market price of
the common stock was $27.
19
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE SHAREHOLDERS,
SOUTHWEST GAS CORPORATION:
We have audited the accompanying consolidated balance sheets of Southwest
Gas Corporation (a California corporation, hereinafter referred to as the
Company) and subsidiaries as of December 31, 1998 and 1997, and the related
consolidated statements of income, stockholders' equity and cash flows for each
of the three years in the period ended December 31, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company and its
subsidiaries as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Las Vegas, Nevada
March 26, 1999
39
20
40 CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
December 31, 1998 1997
- -------------------------------------------------------------------------------------
(Thousands of dollars, except par value)
ASSETS
Utility plant:
Gas plant................................................. $2,020,139 $1,867,824
Less: accumulated depreciation............................ (612,138) (551,083)
Acquisition adjustments................................... 3,881 4,259
Construction work in progress............................. 47,480 39,294
- -------------------------------------------------------------------------------------
Net utility plant (Note 2).............................. 1,459,362 1,360,294
- -------------------------------------------------------------------------------------
Other property and investments.............................. 73,926 64,928
- -------------------------------------------------------------------------------------
Current assets:
Cash and cash equivalents................................. 18,535 17,567
Accounts receivable, net of allowances (Note 3)........... 88,037 78,016
Accrued utility revenue................................... 56,873 54,373
Income tax benefit........................................ -- 19,425
Deferred purchased gas costs (Note 4)..................... 57,595 86,952
Prepaids and other current assets......................... 26,346 32,211
- -------------------------------------------------------------------------------------
Total current assets.................................... 247,386 288,544
- -------------------------------------------------------------------------------------
Deferred charges and other assets (Note 4).................. 50,020 55,293
- -------------------------------------------------------------------------------------
Total assets................................................ $1,830,694 $1,769,059
- -------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, $1 par (authorized -- 45,000,000 shares;
issued and outstanding -- 30,409,616 and 27,387,016
shares)................................................. $ 32,040 $ 29,017
Additional paid-in capital................................ 424,840 360,683
Retained earnings (accumulated deficit)................... 19,520 (3,721)
- -------------------------------------------------------------------------------------
Total common equity..................................... 476,400 385,979
Company-obligated mandatorily redeemable preferred
securities of the Company's subsidiary, Southwest Gas
Capital I, holding solely $61.8 million principal amount
of 9.125% subordinated notes of the Company due 2025
(Note 5)................................................ 60,000 60,000
Long-term debt, less current maturities (Note 6).......... 812,906 778,693
- -------------------------------------------------------------------------------------
Total capitalization.................................... 1,349,306 1,224,672
- -------------------------------------------------------------------------------------
Commitments and contingencies (Note 8)
Current liabilities:
Current maturities of long-term debt (Note 6)............. 5,270 5,621
Short-term debt (Note 7).................................. 52,000 142,000
Accounts payable.......................................... 64,295 62,324
Customer deposits......................................... 24,333 21,945
Accrued taxes............................................. 33,480 21,125
Accrued interest.......................................... 13,872 13,007
Deferred taxes (Note 10).................................. 12,627 24,163
Other current liabilities................................. 44,917 34,222
- -------------------------------------------------------------------------------------
Total current liabilities............................... 250,794 324,407
- -------------------------------------------------------------------------------------
Deferred income taxes and other credits:
Deferred income taxes and investment tax credits (Note
10)..................................................... 179,666 168,282
Other deferred credits (Note 4)........................... 50,928 51,698
- -------------------------------------------------------------------------------------
Total deferred income taxes and other credits........... 230,594 219,980
- -------------------------------------------------------------------------------------
Total capitalization and liabilities........................ $1,830,694 $1,769,059
- -------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
21
CONSOLIDATED STATEMENTS OF INCOME 41
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
Operating revenues:
Gas operating revenues.................................... $799,597 $614,665 $546,361
Construction revenues..................................... 117,712 117,345 97,700
- --------------------------------------------------------------------------------------------
Total operating revenues................................ 917,309 732,010 644,061
- --------------------------------------------------------------------------------------------
Operating expenses:
Net cost of gas sold...................................... 329,849 209,338 187,580
Operations and maintenance................................ 209,172 201,159 198,364
Depreciation and amortization............................. 88,804 84,661 73,699
Taxes other than income taxes............................. 31,646 29,393 28,156
Construction expenses..................................... 103,668 105,198 84,689
- --------------------------------------------------------------------------------------------
Total operating expenses................................ 763,139 629,749 572,488
- --------------------------------------------------------------------------------------------
Operating income............................................ 154,170 102,261 71,573
- --------------------------------------------------------------------------------------------
Other income and (expenses):
Net interest deductions................................... (63,354) (63,218) (54,913)
Preferred securities distributions (Note 5)............... (5,475) (5,475) (5,475)
Other income (deductions), net (Note 11).................. (1,390) (12,240) (737)
- --------------------------------------------------------------------------------------------
Total other income and (expenses)....................... (70,219) (80,933) (61,125)
- --------------------------------------------------------------------------------------------
Income before income taxes.................................. 83,951 21,328 10,448
Income tax expense (Note 10)................................ 36,414 4,859 3,874
- --------------------------------------------------------------------------------------------
Net income.................................................. $ 47,537 $ 16,469 $ 6,574
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Basic earnings per share (Note 15).......................... $ 1.66 $ 0.61 $ 0.25
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Diluted earnings per share (Note 15)........................ $ 1.65 $ 0.61 $ 0.25
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
Average number of common shares outstanding................. 28,611 27,069 25,888
Average shares outstanding (assuming dilution).............. 28,815 27,193 25,955
The accompanying notes are an integral part of these statements.
22
42 CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Year Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------------
(Thousands of dollars)
CASH FLOW FROM OPERATING ACTIVITIES:
Net income................................................ $ 47,537 $ 16,469 $ 6,574
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization........................... 88,804 84,661 73,699
Deferred income taxes................................... (152) 47,476 17,453
Changes in current assets and liabilities:
Accounts receivable, net of allowances................ (10,021) (7,913) (17,886)
Accrued utility revenue............................... (2,500) (7,873) (2,600)
Deferred purchased gas costs.......................... 29,357 (96,384) (23,344)
Accounts payable...................................... 1,971 12,373 4,964
Accrued taxes......................................... 31,780 (8,277) (19,139)
Other current assets and liabilities.................. 15,763 2,004 2,498
Other................................................... 978 13,889 9,976
- -----------------------------------------------------------------------------------------------
Net cash provided by operating activities............... 203,517 56,425 52,195
- -----------------------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES:
Construction expenditures and property additions.......... (194,621) (169,614) (218,835)
Proceeds from bank sale................................... -- -- 191,662
Other..................................................... 4,327 (1,308) (22,112)
- -----------------------------------------------------------------------------------------------
Net cash used in investing activities................... (190,294) (170,922) (49,285)
- -----------------------------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES:
Issuance of common stock, net............................. 67,180 12,205 18,110
Dividends paid............................................ (23,676) (22,177) (21,311)
Issuance of long-term debt, net........................... 40,864 120,321 164,876
Retirement of long-term debt, net......................... (6,623) (7,565) (248,531)
Issuance (repayment) of short-term debt................... (90,000) 21,000 81,058
- -----------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities..... (12,255) 123,784 (5,798)
- -----------------------------------------------------------------------------------------------
Change in cash and temporary cash investments............. 968 9,287 (2,888)
Cash at beginning of period............................... 17,567 8,280 11,168
- -----------------------------------------------------------------------------------------------
Cash at end of period..................................... $ 18,535 $ 17,567 $ 8,280
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
Supplemental information:
Interest paid, net of amounts capitalized................. $ 61,164 $ 58,771 $ 60,008
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
Income taxes paid (received), net......................... $ 4,968 $ (33,954) $ 18,682
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these statements.
23
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY 43
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Common Stock Additional
------------------ Paid-in Retained
Shares Amount Capital Earnings Total
- ------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
DECEMBER 31, 1995............................ 24,467 $ 26,097 $ 312,631 $ 17,322 $ 356,050
Common stock issuances..................... 2,266 2,266 36,501 38,767
Net income................................. 6,574 6,574
Dividends declared
Common: $0.82 per share.................. (21,775) (21,775)
- ------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996............................ 26,733 28,363 349,132 2,121 379,616
Common stock issuances..................... 654 654 11,551 12,205
Net income................................. 16,469 16,469
Dividends declared
Common: $0.82 per share.................. (22,311) (22,311)
- ------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997............................ 27,387 29,017 360,683 (3,721) 385,979
Common stock issuances..................... 3,023 3,023 64,157 67,180
Net income................................. 47,537 47,537
Dividends declared
Common: $0.82 per share.................. (24,296) (24,296)
- ------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998............................ 30,410* $ 32,040 $ 424,840 $ 19,520 $ 476,400
- ------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------
* At December 31, 1998 2.1 million common shares were registered and
available for issuance under provisions of the Employee Investment Plan, the
Stock Incentive Plan, and the Dividend Reinvestment and Stock Purchase Plan.
The accompanying notes are an integral part of these statements.
24
44 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
NOTE 1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS. Southwest Gas Corporation (the Company) is comprised of
two segments: natural gas operations (Southwest or the natural gas operations
segment) and construction services. Southwest purchases, transports, and
distributes natural gas to customers in portions of Arizona, Nevada, and
California. Southwest's public utility rates, practices, facilities, and service
territories are subject to regulatory oversight. The timing and amount of rate
relief can materially impact results of operations. Natural gas sales are
seasonal, peaking during the winter months. Variability in weather from normal
temperatures can materially impact results of operations. Northern Pipeline
Construction Co. (Northern or the construction services segment), a wholly owned
subsidiary, is a full-service underground piping contractor which provides
utility companies with trenching and installation, replacement, and maintenance
services for energy distribution systems.
BASIS OF PRESENTATION. The Company follows generally accepted accounting
principles (GAAP) in accounting for all of its businesses. Accounting for the
natural gas utility operations conforms with GAAP as applied to regulated
companies and as prescribed by federal agencies and the commissions of the
various states in which the utility operates. The preparation of financial
statements in conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the reporting
period. Actual results could differ from those estimates.
CONSOLIDATION. The accompanying financial statements are presented on a
consolidated basis and include the accounts of Southwest Gas Corporation and all
wholly owned subsidiaries. All significant intercompany balances and
transactions have been eliminated with the exception of transactions between
Southwest and Northern. Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," provides that
intercompany profits on sales to regulated affiliates should not be eliminated
in consolidation if the sales price is reasonable and if future revenues
approximately equal to the sales price will result from the rate-making process.
Management believes these two criteria are being met.
NET UTILITY PLANT. Net utility plant includes gas plant at original cost, less
the accumulated provision for depreciation and amortization, plus the
unamortized balance of acquisition adjustments. Original cost includes
contracted services, material, payroll and related costs such as taxes and
benefits, general and administrative expenses, and an allowance for funds used
during construction less contributions in aid of construction.
DEFERRED PURCHASED GAS COSTS. The various regulatory commissions have
established procedures to enable Southwest to adjust its billing rates for
changes in the cost of gas purchased. The difference between the current cost of
gas purchased and the cost of gas recovered in billed rates is deferred.
Generally, these deferred amounts are recovered or refunded within one to two
years. Southwest must first obtain regulatory approval before changing the rates
it charges for recovery of gas costs.
INCOME TAXES. The Company uses the asset and liability method of accounting for
income taxes. Under the asset and liability method, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using enacted tax rates
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 45
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in the period that
includes the enactment date.
For regulatory and financial reporting purposes, investment tax credits
(ITC) related to gas utility operations are deferred and amortized over the life
of related fixed assets.
GAS OPERATING REVENUES. Revenues are recorded when customers are billed.
Customer billings are based on monthly meter reads and are calculated in
accordance with applicable tariffs. Southwest also recognizes accrued utility
revenues for the estimated amount of services rendered between the meter-reading
dates in a particular month and the end of such month.
CONSTRUCTION REVENUES. The majority of Northern's contracts are performed under
unit price contracts. These contracts state prices per unit of installation.
Revenues are recorded as installations are completed. Fixed-price contracts use
the percentage of completion method of accounting and, therefore, take into
account the cost, estimated earnings, and revenue to date on contracts not yet
completed. The amount of revenue recognized is based on costs expended to date
relative to anticipated final contract costs. Revisions in estimates of cost and
earnings during the course of the work are reflected in the accounting period in
which the facts requiring revision become known. If a loss on a contract becomes
known or is anticipated, the entire amount of the estimated ultimate loss is
recognized at that time in the financial statements.
DEPRECIATION AND AMORTIZATION. Utility plant depreciation is computed on the
straight-line remaining life method at composite rates considered sufficient to
amortize costs over estimated service lives, including components which adjust
for salvage value and removal costs, as approved by the appropriate regulatory
agency. When plant is retired from service, the original cost of plant,
including costs of removal, less salvage, is charged to the accumulated
provision for depreciation. Acquisition adjustments are amortized, as ordered by
regulators, over periods which approximate the remaining estimated life of the
acquired properties. Costs related to refunding utility debt and debt issuance
expenses are deferred and amortized over the weighted-average lives of the new
issues. Other regulatory assets, when appropriate, are amortized over time
periods authorized by regulators. Nonutility property and equipment are
depreciated on a straight-line method based on the estimated useful lives of the
related assets.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC). AFUDC represents the cost
of both debt and equity funds used to finance utility construction. AFUDC is
capitalized as part of the cost of utility plant. The Company capitalized $2.4
million in 1998, $1.6 million in 1997, and $1.8 million in 1996 of AFUDC related
to natural gas utility operations. The debt portion of AFUDC is reported in the
consolidated statements of income as an offset to net interest deductions and
the equity portion is reported as other income. Utility plant construction
costs, including AFUDC, are recovered in authorized rates through depreciation
when completed projects are placed into operation, and general rate relief is
requested and granted.
EARNINGS PER SHARE. The Company implemented Statement of Financial Accounting
Standards (SFAS) No. 128, "Earnings Per Share," for 1997 financial reporting
purposes. Basic earnings per share (EPS) are calculated by dividing net income
by the weighted-average number of shares outstanding during the period. Diluted
EPS includes additional weighted-average common stock equivalents (stock options
and performance shares). Unless otherwise noted, the term "Earnings Per Share"
refers to Basic EPS. A
26
46 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
reconciliation of the shares used in the Basic and Diluted EPS calculations is
shown in the following table. Net income was the same for Basic and Diluted EPS
calculations.
1998 1997 1996
- -----------------------------------------------------------------------------------------------------
(In thousands)
Average basic shares....................................... 28,611 27,069 25,888
Effect of dilutive securities
Stock options.......................................... 108 61 27
Performance shares..................................... 96 63 40
- -----------------------------------------------------------------------------------------------------
Average diluted shares..................................... 28,815 27,193 25,955
- -----------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------
CASH FLOWS. For purposes of reporting consolidated cash flows, cash and cash
equivalents include cash on hand and financial instruments with a maturity of
three months or less, but exclude funds held in trust from the issuance of
industrial development revenue bonds.
RECLASSIFICATIONS. Certain reclassifications have been made to amounts shown for
prior years to conform to the current-year presentation.
NOTE 2.
UTILITY PLANT
Net utility plant as of December 31, 1998 and 1997 was as follows (thousands of
dollars):
December 31, 1998 1997
- ---------------------------------------------------------------------------------------------
Gas plant:
Storage................................................. $ 3,316 $ 3,233
Transmission............................................ 170,512 169,033
Distribution............................................ 1,598,703 1,458,707
General................................................. 186,468 178,838
Other................................................... 61,140 58,013
- ---------------------------------------------------------------------------------------------
2,020,139 1,867,824
Less: accumulated depreciation.............................. (612,138) (551,083)
Acquisition adjustments, net................................ 3,881 4,259
Construction work in progress............................... 47,480 39,294
- ---------------------------------------------------------------------------------------------
Net utility plant....................................... $1,459,362 $1,360,294
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
Depreciation expense on gas plant was $78.4 million in 1998, $73.5 million
in 1997, and $66.9 million in 1996.
LEASES AND RENTALS. Southwest leases the liquefied natural gas (LNG) facilities
on its northern Nevada system, a portion of its corporate headquarters office
complex in Las Vegas, and its administrative offices in Phoenix. The leases
provide for current terms which expire in 2003, 2017, and 2004, respectively,
with optional renewal terms available at the expiration dates. The rental
payments for the LNG facilities are $6.7 million annually and $30 million in the
aggregate. The rental payments for the corporate headquarters office complex are
$1.8 million for each year 1999 through 2002, $1.9 in 2003 and $28.2 million
cumulatively thereafter. The rental payments for the Phoenix administrative
offices are $1.2 million for 1999 and 2000, $1.3 million for each of the years
2001 through 2003, and $1 million in the final year of the lease. In addition to
the above, the Company leases certain office and construction equipment. The
majority of these leases are short-term. These
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 47
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
leases are accounted for as operating leases, and for the gas segment are
treated as such for regulatory purposes. Rentals included in operating expenses
for all operating leases were $22.6 million in 1998, $20.7 million in 1997, and
$19.9 million in 1996. These amounts include Northern lease expenses of
approximately $7.6 million in 1998, $6.7 million in 1997, and $6 million in 1996
for various short-term leases of equipment and temporary office sites.
The following is a schedule of future minimum lease payments for
noncancellable operating leases (with initial or remaining terms in excess of
one year) as of December 31, 1998 (thousands of dollars):
Year Ending December 31,
- ---------------------------------------------------------------------
1999........................................................ $10,213
2000........................................................ 10,004
2001........................................................ 10,062
2002........................................................ 9,999
2003........................................................ 6,470
Thereafter.................................................. 29,197
- ---------------------------------------------------------------------
Total minimum lease payments................................ $75,945
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
NOTE 3.
RECEIVABLES AND RELATED ALLOWANCES
Business activity with respect to gas utility operations is conducted with
customers located within the three-state region of Arizona, Nevada, and
California. At December 31, 1998, gas utility customer accounts receivable were
$67.3 million. Approximately 57 percent of the gas utility customers were in
Arizona, 33 percent in Nevada, and 10 percent in California. Although the
Company seeks to minimize its credit risk related to utility operations by
requiring security deposits from new customers, imposing late fees, and actively
pursuing collection on certain accounts, some accounts are ultimately not
collected. Provisions for uncollectible accounts are recorded monthly, as
needed, and are included in the ratemaking process as a cost of service.
Activity in the allowance for uncollectibles is summarized as follows (thousands
of dollars):
Allowance
for Uncollectibles
- ----------------------------------------------------------------------------------
Balance, December 31, 1995.................................. $ 1,227
Additions charged to expense............................ 1,285
Accounts written off, less recoveries................... (1,002)
- ----------------------------------------------------------------------------------
Balance, December 31, 1996.................................. 1,510
Additions charged to expense............................ 1,495
Accounts written off, less recoveries................... (1,427)
- ----------------------------------------------------------------------------------
Balance, December 31, 1997.................................. 1,578
Additions charged to expense............................ 2,057
Accounts written off, less recoveries................... (2,290)
- ----------------------------------------------------------------------------------
Balance, December 31, 1998.................................. $ 1,345
- ----------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------
28
48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
NOTE 4.
REGULATORY ASSETS AND LIABILITIES
Natural gas operations are subject to the regulation of the Arizona
Corporation Commission (ACC), the Public Utilities Commission of Nevada (PUCN),
the California Public Utilities Commission (CPUC), and the Federal Energy
Regulatory Commission (FERC). The Company's accounting policies conform to
generally accepted accounting principles applicable to rate-regulated
enterprises and reflect the effects of the ratemaking process. Such effects
concern mainly the time at which various items enter into the determination of
net income in accordance with the principle of matching costs with related
revenues.
The following table represents existing regulatory assets and liabilities
(thousands of dollars):
December 31, 1998 1997
- -----------------------------------------------------------------------------------------
Regulatory assets:
Deferred purchased gas costs............................ $ 57,595 $ 86,952
SFAS No. 109 -- Income taxes, net....................... 7,870 9,651
Unamortized premium on reacquired debt.................. 16,107 16,803
Other................................................... 21,478 23,048
- -----------------------------------------------------------------------------------------
103,050 136,454
Regulatory liabilities:
Supplier and other rate refunds due customers........... (2,809) (1,059)
Other................................................... (241) (1,124)
- -----------------------------------------------------------------------------------------
Net regulatory assets....................................... $100,000 $134,271
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
NOTE 5.
PREFERRED SECURITIES
PREFERRED SECURITIES OF SOUTHWEST GAS CAPITAL I. In October 1995, Southwest Gas
Capital I (the Trust), a consolidated wholly owned subsidiary of the Company,
issued $60 million of 9.125% Trust Originated Preferred Securities (the
Preferred Securities). In connection with the Trust's issuance of the Preferred
Securities and the related purchase by the Company of all of the Trust's common
securities (the Common Securities), the Company issued to the Trust $61.8
million principal amount of its 9.125% Subordinated Deferrable Interest Notes,
due 2025 (the Subordinated Notes). The sole assets of the Trust are and will be
the Subordinated Notes. The interest and other payment dates on the Subordinated
Notes correspond to the distribution and other payment dates on the Preferred
Securities and Common Securities. Under certain circumstances, the Subordinated
Notes may be distributed to the holders of the Preferred Securities and holders
of the Common Securities in liquidation of the Trust. The Subordinated Notes are
redeemable at the option of the Company on or after December 31, 2000, at a
redemption price of $25 per Subordinated Note plus accrued and unpaid interest.
In the event that the Subordinated Notes are repaid, the Preferred Securities
and the Common Securities will be redeemed on a pro rata basis at $25 per
Preferred Security and Common Security plus accumulated and unpaid
distributions. The Company's obligations under the Subordinated Notes, the
Declaration of Trust (the agreement under which the Trust was formed), the
guarantee of payment of certain distributions, redemption payments and
liquidation payments with respect to the Preferred Securities to the extent the
Trust has funds available therefor and the indenture governing the Subordinated
Notes, including the Company's agreement pursuant to such indenture to pay all
fees and expenses of the Trust, other than with respect to the Preferred
Securities and Common Securities, taken together, constitute a full and
unconditional guarantee on a subordinated basis by the Company of payments due
on the Preferred Securities. As of December 31, 1998, 2.4 million Preferred
Securities were outstanding.
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 49
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The Company has the right to defer payments of interest on the Subordinated
Notes by extending the interest payment period at any time for up to 20
consecutive quarters (each, an Extension Period). If interest payments are so
deferred, distributions will also be deferred. During such Extension Period,
distributions will continue to accrue with interest thereon (to the extent
permitted by applicable law) at an annual rate of 9.125% per annum compounded
quarterly. There could be multiple Extension Periods of varying lengths
throughout the term of the Subordinated Notes. If the Company exercises the
right to extend an interest payment period, the Company shall not during such
Extension Period (i) declare or pay dividends on, or make a distribution with
respect to, or redeem, purchase or acquire or make a liquidation payment with
respect to, any of its capital stock, or (ii) make any payment of interest,
principal or premium, if any, on or repay, repurchase, or redeem any debt
securities issued by the Company that rank equal with or junior to the
Subordinated Notes; provided, however, that restriction (i) above does not apply
to any stock dividends paid by the Company where the dividend stock is the same
as that on which the dividend is being paid. The Company has no present
intention of exercising its right to extend the interest payment period.
NOTE 6.
LONG-TERM DEBT
December
31, 1998 1997
- --------------------------------------------------------------------------------
Carrying Market Carrying Market
Amount Value Amount Value
- -------------------------------------------------------------------------------------------------------
(Thousands of dollars)
Debentures:
9 3/4% Series F, due 2002............................... $100,000 $111,672 $100,000 $112,120
7 1/2% Series, due 2006................................. 75,000 83,063 75,000 78,116
8% Series, due 2026..................................... 75,000 84,301 75,000 82,028
Medium-term notes, 7.59% series, due 2017............... 25,000 26,817 25,000 26,214
Medium-term notes, 7.78% series, due 2022............... 25,000 27,458 25,000 26,735
Medium-term notes, 7.92% series, due 2027............... 25,000 27,852 25,000 27,121
Medium-term notes, 6.89% series, due 2007............... 17,500 18,242 17,500 17,327
Medium-term notes, 6.76% series, due 2027............... 7,500 7,277 7,500 7,079
Medium-term notes, 6.27% series, due 2008............... 25,000 24,997 -- --
Unamortized discount.................................... (3,452) -- (3,592) --
- -------------------------------------------------------------------------------------------------------
371,548 346,408
- -------------------------------------------------------------------------------------------------------
Revolving credit facility................................... 200,000 200,000 200,000 200,000
- -------------------------------------------------------------------------------------------------------
Industrial development revenue bonds:
Variable-rate bonds
Series A, due 2028................................. 50,000 50,000 50,000 50,000
Less funds held in trust........................... (19,684) -- (25,926) --
- -------------------------------------------------------------------------------------------------------
30,316 24,074
- -------------------------------------------------------------------------------------------------------
Fixed-rate bonds
7.30% 1992 Series A, due 2027...................... 30,000 28,484 30,000 30,288
7.50% 1992 Series B, due 2032...................... 100,000 96,777 100,000 102,883
6.50% 1993 Series A, due 2033...................... 75,000 63,591 75,000 67,661
Unamortized discount............................... (3,448) -- (3,551) --
- -------------------------------------------------------------------------------------------------------
201,552 201,449
- -------------------------------------------------------------------------------------------------------
Other....................................................... 14,760 -- 12,383 --
- -------------------------------------------------------------------------------------------------------
818,176 784,314
Less current maturities..................................... (5,270) (5,621)
- -------------------------------------------------------------------------------------------------------
Long-term debt, less current maturities..................... $812,906 $778,693
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
30
50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
In October 1996, the Company filed a $250 million shelf registration
statement. In connection with this registration statement, the Company may
offer, up to the registered amount, any combination of debt securities,
preferred stock, depositary shares, and common stock. The Company filed a
prospectus supplement in December 1996 identifying $150 million of the shelf as
medium-term notes. During 1997 and 1998, the Company issued a total of $125
million in medium-term notes.
In June 1997, the Company entered into a $350 million revolving credit
agreement which replaced a previous $200 million term-loan facility and a $150
million short-term credit line. Revolving credit loans bear interest at either
the London Interbank Offering Rate (LIBOR) plus or minus a competitive margin or
prime rate plus one half of one percent of the Federal Funds rate. Any amounts
borrowed under the revolving credit agreement become payable in June 2002. The
Company has designated $200 million of the total facility as long-term debt and
uses the remaining $150 million for working capital purposes and has designated
the related outstanding amounts as short-term debt.
The interest rate on the variable-rate industrial development revenue bonds
(IDRB) is established on a weekly basis and averaged 3.74 percent in 1998, 4.18
percent in 1997, and 4.16 percent in 1996. At the option of the Company, the
interest period can be converted from a weekly rate to a daily-term or
variable-term rate.
The fair value of the revolving credit facility approximates carrying
value. Market values for the debentures and fixed-rate IDRB were determined
based on dealer quotes using trading records for December 31, 1998 and 1997, as
applicable, and other secondary sources which are customarily consulted for data
of this kind. The carrying value of the IDRB Series due 2028 was used as the
estimate of fair value based upon the variable interest rate of the bonds.
Estimated maturities of long-term debt for the next five years are expected
to be $5.3 million, $4.9 million, $2.5 million, $302 million, and $95,000,
respectively.
NOTE 7.
SHORT-TERM DEBT
In June 1997, a portion of the $350 million revolving credit facility,
discussed in Note 6, replaced various credit lines which aggregated $150
million. Short-term borrowings were $52 million and $142 million at December 31,
1998 and 1997, respectively. The weighted-average interest rates on these
borrowings were 7.62 percent at December 31, 1998 and 6.54 percent at December
31, 1997.
In October 1997, the Company entered into a $50 million unsecured line of
credit agreement with various banks, for general working capital purposes, which
expired in October 1998. During 1998 and 1997, no amounts were outstanding on
this line of credit.
NOTE 8.
COMMITMENTS AND CONTINGENCIES
LEGAL PROCEEDINGS. The Company has been named as defendant in various legal
proceedings. The ultimate dispositions of these proceedings are not presently
determinable; however, it is the opinion of management that no litigation to
which the Company is subject will have a material adverse impact on its
financial position or results of operations.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 51
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
NOTE 9.
EMPLOYEE BENEFITS
Southwest has a noncontributory qualified retirement plan with defined
benefits covering substantially all employees. Southwest also provides
postretirement benefits other than pensions (PBOP) to its qualified retirees for
health care, dental, and life insurance benefits.
In 1998, the Company adopted SFAS No. 132, "Employers' Disclosures About
Pensions and Other Postretirement Benefits," which standardized the disclosure
requirements for pensions and other postretirement benefits. SFAS No. 132 did
not change the measurement or recognition of amounts related to those plans.
Prior-year amounts were reclassified to conform to the new standard. The
following tables set forth the qualified retirement plan and PBOP funded status
and amounts recognized on the Consolidated Balance Sheets and Statements of
Income.
Qualified
Retirement Plan PBOP
-------------------- --------------------
1998 1997 1998 1997
- ---------------------------------------------------------------------------------------------------
(Thousands of dollars)
CHANGE IN BENEFIT OBLIGATIONS
Benefit obligation for service rendered to date at
beginning of year (PBO/APBO)....................... $190,389 $187,183 $ 21,698 $ 23,888
Service cost......................................... 9,130 9,630 504 567
Interest cost........................................ 14,092 12,945 1,591 1,638
Actuarial loss (gain)................................ 14,221 (14,870) 1,334 (3,415)
Benefits paid........................................ (5,000) (4,499) (1,150) (980)
- ---------------------------------------------------------------------------------------------------
Benefit obligation at end of year (PBO/APBO)......... 222,832 190,389 23,977 21,698
- ---------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Market value of plan assets at beginning of year..... 232,413 195,994 3,581 2,408
Actual return on plan assets......................... 28,272 35,305 487 479
Employer contributions............................... -- 5,613 2,611 693
Benefits paid........................................ (5,000) (4,499) -- --
- ---------------------------------------------------------------------------------------------------
Market value of plan assets at end of year........... 255,685 232,413 6,679 3,580
- ---------------------------------------------------------------------------------------------------
Funded status -- over (under)........................ 32,853 42,024 (17,298) (18,117)
Unrecognized net actuarial loss (gain)............... (44,467) (48,647) (231) (1,151)
Unrecognized transition obligation (2004/2012)....... 4,142 4,979 12,137 13,004
Unrecognized prior service cost...................... 295 352 -- --
- ---------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost....................... $ (7,177) $ (1,292) $ (5,392) $ (6,264)
- ---------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS
AS OF DECEMBER 31,
Discount rate........................................ 7.00% 7.50% 7.00% 7.50%
Expected return on plan assets....................... 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase........................ 4.50% 4.75% 4.50% 4.75%
For PBOP measurement purposes, a seven percent annual rate of increase in
the per capita cost of covered health care benefits is assumed for 1999. The
rate is assumed to decrease one-half of one percent per
32
52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
year until 2003, at which time the average annual increase is projected to be
five percent. The Company makes fixed contributions for health care benefits of
employees who retire after 1988, but pays up to 100 percent of covered health
care costs for employees who retired prior to 1989. The assumed annual rate
increase noted above applies to the benefit obligations of pre-1989 retirees
only.
Components of net periodic benefit cost:
Qualified Retirement Plan PBOP
------------------------------ ------------------------
1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
(Thousands of dollars)
Service cost.................................. $ 9,130 $ 9,630 $ 8,762 $ 504 $ 567 $ 521
Interest cost................................. 14,092 12,945 11,992 1,591 1,638 1,638
Expected return on plan assets................ (18,199) (16,270) (14,428) (349) (244) (175)
Amortization of prior service costs........... 57 57 57 -- -- --
Amortization of unrecognized transition
obligation.................................. 837 837 837 867 867 867
Amortization of net (gain) loss............... (32) -- -- -- 12 53
- ---------------------------------------------------------------------------------------------------------
Net periodic benefit cost..................... $ 5,885 $ 7,199 $ 7,220 $2,613 $2,840 $2,904
- ---------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------
In addition to the qualified retirement plan, Southwest has a separate
unfunded supplemental retirement plan which is limited to officers. The plan is
noncontributory with defined benefits. Plan costs were $2 million in 1998, $2
million in 1997, and $1.8 million in 1996. The accumulated benefit obligation of
the plan was $17.1 million at December 31, 1998.
The Employees' Investment Plan provides for purchases of the Company's
common stock or certain other investments by eligible Southwest employees
through deductions of up to 16 percent of base compensation, subject to IRS
limitations. Southwest matches one-half of amounts deferred up to six percent of
an employee's annual compensation. The cost of the plan was $2.6 million in
1998, $2.5 million in 1997, and $2.6 million in 1996. Northern has a separate
plan, the cost and liability for which are not significant.
Southwest has a deferred compensation plan for all officers and members of
the Board. The plan provides the opportunity to defer up to 100 percent of
annual cash compensation. Southwest matches one-half of amounts deferred up to
six percent of an officer's annual salary. Payments of compensation deferred,
plus interest, are made in equal monthly installments over 5, 10, 15, or 20
years, as elected by the participant. Deferred compensation earns interest at a
rate determined each January. The interest rate represents 150 percent of
Moody's Seasoned Corporate Bond Index.
At December 31, 1998, the Company had two stock-based compensation plans.
These plans are accounted for in accordance with APB Opinion No. 25 "Accounting
for Stock Issued to Employees." In connection with the stock-based compensation
plans, the Company recognized compensation expense of $2.1 million in 1998, $1
million in 1997, and $571,000 in 1996. Had compensation cost been determined
based on the fair value of the awards at the grant dates, net income and
earnings per share would have reflected the pro forma amounts indicated below
(thousands of dollars, except per share amounts):
1998 1997 1996
- ---------------------------------------------------------------------------------------------------
Net income............................................ As reported $47,537 $16,469 $6,574
Pro forma 47,869 16,318 6,535
Basic earnings per share.............................. As reported 1.66 0.61 0.25
Pro forma 1.67 0.60 0.25
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 53
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
With respect to the first plan, the Company may grant options to purchase
shares of common stock to key employees and outside directors. Each option has
an exercise price equal to the market price of Company common stock on the date
of grant and a maximum term of 10 years. In 1998, 118,000 options were granted.
The options vest 40 percent at the end of year one and 30 percent at the end of
years two and three. The grant date fair value of the options was estimated
using the extended binomial option pricing model. The following assumptions were
used in the valuation calculation:
1998 1997 1996
- ------------------------------------------------------------------------------------------------------
Dividend yield.................................. 3.15% 4.09% 4.65%
Risk-free interest rate range................... 5.36 to 5.63% 5.28 to 5.38% 5.83 to 6.42%
Expected volatility range....................... 22 to 25% 22 to 24% 22 to 25%
Expected life................................... 1 to 3 years 1 to 3 years 1 to 3 years
The following tables summarize the Company's stock option plan activity and
related information (thousands of options):
1998 1997 1996
----------------------- ----------------------- -----------------------
Weighted- Weighted- Weighted-
average average average
Number exercise Number exercise Number exercise
of options price of options price of options price
- ------------------------------------------------------------------------------------------------------------
Outstanding at the beginning of
the year..................... 472 $15.96 380 $15.00 -- --
Granted during the year........ 118 23.04 121 18.78 380 $15.00
Exercised during the year...... -- -- -- -- -- --
Forfeited during the year...... (3) 15.80 (29) 15.14 -- --
Expired during the year........ -- -- -- -- -- --
- ------------------------------------------------------------------------------------------------------------
Outstanding at year end........ 587 $17.38 472 $15.96 380 $15.00
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
Exercisable at year end........ 295 $16.19 141 $15.00 -- --
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
The weighted-average grant-date fair value of options granted was $2.68 for
1998, $2.26 for 1997, and $1.79 for 1996. The exercise prices for the options
granted range from $15.00 to $23.06. On December 31, 1998, the options
outstanding had a weighted-average remaining contractual life of approximately
8.1 years.
In addition to the option plan, the Company may issue restricted stock in
the form of performance shares to encourage key employees to remain in its
employment to achieve short-term and long-term performance goals. Plan
participants are eligible to receive a cash bonus (i.e., short-term incentive)
and performances shares (i.e., long-term incentive). The performance shares vest
after three years from issuance and are subject
34
54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
to a final adjustment as determined by the Board of Directors. The following
table summarizes the activity of this plan (thousands of shares):
Year Ended December 31, 1998 1997 1996
- ----------------------------------------------------------------------------------------
Nonvested performance shares at beginning of year........... 126 93 41
Performance shares granted.................................. 67 59 64
Performance shares forfeited................................ -- -- --
Shares vested and issued.................................... (21) (26) (12)
- ----------------------------------------------------------------------------------------
Nonvested performance shares at end of year................. 172 126 93
- ----------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------
Grant date fair value of award.............................. $18.69 $19.25 $17.63
- ----------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------
NOTE 10.
INCOME TAXES
Income tax expense (benefit) consists of the following:
Year Ended December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------
(Thousands of dollars)
Current:
Federal................................................... $32,267 $(42,921) $(15,087)
State..................................................... 2,519 (2,227) (1,566)
- ---------------------------------------------------------------------------------------------
34,786 (45,148) (16,653)
- ---------------------------------------------------------------------------------------------
Deferred:
Federal................................................... (268) 47,614 18,832
State..................................................... 1,896 2,393 1,695
- ---------------------------------------------------------------------------------------------
1,628 50,007 20,527
- ---------------------------------------------------------------------------------------------
Total income tax expense................................ $36,414 $ 4,859 $ 3,874
- ---------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------
Deferred income tax expense (benefit) consists of the following significant
components:
Year Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------
(Thousands of dollars)
Deferred federal and state:
Property-related items.................................. $ 15,586 $19,006 $11,586
Purchased gas cost adjustments.......................... (10,344) 37,156 8,437
All other deferred...................................... (2,746) (5,287) 1,372
- --------------------------------------------------------------------------------------------
Total deferred federal and state................... 2,496 50,875 21,395
Deferred investment tax credit, net......................... (868) (868) (868)
- --------------------------------------------------------------------------------------------
Total deferred income tax expense.................. $ 1,628 $50,007 $20,527
- --------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 55
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The consolidated effective income tax rate for the period ended December
31, 1998 and the two prior periods differs from the federal statutory income tax
rate. The sources of these differences and the effect of each are summarized as
follows:
Year Ended December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------
Federal statutory income tax rate........................... 35.0% 35.0% 35.0%
Net state tax liability................................. 5.5 4.2 5.0
Property-related items.................................. 1.3 3.8 8.8
Effect of Internal Revenue Service Examination.......... -- (16.0) --
Tax credits............................................. (1.0) (4.0) (8.3)
Tax exempt interest..................................... (0.3) (1.7) (3.7)
Corporate owned life insurance.......................... 1.0 (1.0) (4.0)
All other differences................................... 1.9 2.5 4.3
- ---------------------------------------------------------------------------------------
Consolidated effective income tax rate.................. 43.4% 22.8% 37.1%
- ---------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------
Deferred tax assets and liabilities consist of the following:
December 31, 1998 1997
- -----------------------------------------------------------------------------------------
(Thousands of dollars)
Deferred tax assets:
Deferred income taxes for future amortization of ITC.... $ 11,673 $ 12,201
Employee benefits....................................... 9,779 7,459
Other................................................... 8,996 9,278
Valuation allowance..................................... -- --
- -----------------------------------------------------------------------------------------
30,448 28,938
- -----------------------------------------------------------------------------------------
Deferred tax liabilities:
Property-related items, including accelerated
depreciation.............................................. 149,095 133,539
Regulatory balancing accounts........................... 23,280 33,626
Property-related items previously flowed-through........ 19,543 21,851
Unamortized ITC......................................... 17,271 18,138
Debt-related costs...................................... 6,258 6,458
Other................................................... 7,294 7,771
- -----------------------------------------------------------------------------------------
222,741 221,383
- -----------------------------------------------------------------------------------------
Net deferred tax liabilities................................ $192,293 $192,445
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
Current..................................................... $ 12,627 $ 24,163
Noncurrent.................................................. 179,666 168,282
- -----------------------------------------------------------------------------------------
Net deferred tax liabilities................................ $192,293 $192,445
- -----------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------
At December 31, 1998, the Company has an Arizona net operating loss
carryforward of $35 million which expires in 2002. The Company anticipates
utilizing the net operating loss carryforward prior to expiration. Additionally,
the Company has an alternative minimum tax credit carryforward of approximately
$7.6 million, which can be carried forward indefinitely.
36
56 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
NOTE 11.
CALIFORNIA EXPANSION AND LNG CONSTRUCTION PROJECTS
NORTHERN CALIFORNIA EXPANSION PROJECT. In December 1993, Southwest filed an
application with the California Public Utilities Commission (CPUC) to expand its
northern California service territory and extend service into Truckee,
California. The application included a proposed regulatory mechanism for
recovering the cost of the expansion. In May 1994, rate and cost recovery issues
related to the expansion application were combined by the CPUC with a January
1994 general rate application Southwest had filed with the CPUC. In September
1994, a Joint Motion and Stipulation and Settlement Agreement (Settlement) was
presented to the CPUC which resolved the general rate case and addressed the
expansion related cost recovery issues. In December 1994, the Settlement was
approved. In April 1995, Southwest received CPUC approval for the certificate of
public convenience and necessity to serve the expansion areas.
In its filing, Southwest had indicated that expansion into Truckee would
occur in three phases and result in the conversion of an estimated 9,200
customers to natural gas service from their existing fuel, primarily propane.
The CPUC established a cost cap of $29.1 million for the project.
In 1995, Southwest completed Phase I of the expansion project, which
involved transmission system reinforcement and distribution system expansion to
accommodate approximately 940 customers. Construction costs of $7.1 million were
on target with the cost estimate approved by the CPUC.
Phase II of the project involved extending the transmission system to
Truckee and expanding the distribution system to accommodate an estimated 4,200
customers. The cost cap apportioned to Phase II was approximately $13.8 million.
The incurred cost of Phase II was $28.8 million. An estimated $9.2 million of
the Phase II cost overrun was due to changes in project scope, such as
adjustments for design changes required by governmental bodies, changes in
facilities necessitated by requirements beyond Southwest's control, and costs
incurred to accommodate customer service requests.
Examples of adjustments for changes in project scope included the
requirement to haul excavated soil off-site to be screened whereas normal and
anticipated practice is to screen on-site, asphalt repairs which were greater
than expected due to increased paving requirements imposed after construction
started, and the installation of more facilities under asphalt than anticipated.
Other unexpected or externally imposed costs pertained to extended yard lines,
underground boring, environmental studies, right-of-way acquisitions, and
engineering design work.
Due to the Phase II cost overruns and difficult construction environment
experienced, construction of Phase III was postponed to reevaluate the economics
of completing the project.
In July 1997, Southwest filed an application requesting authorization from
the CPUC to modify the terms and conditions of the certificate of public
convenience and necessity granted in 1995. In this application, Southwest
requested that the originally approved cost cap of $29.1 million be increased to
$46.8 million; that the scope of Phase III construction be revised to include
only an estimated 2,900 of the initially estimated 4,200 customers; and that
customer applicants desiring service in the expansion area who were not
identified to receive service during the expansion phases as modified within the
new application be subject to the existing main and service extension rules.
Southwest proposed to recover the incremental costs above the original cost cap
through a surcharge mechanism. Concurrently, the Truckee town manager, on behalf
of the Truckee Town Council, wrote a letter to the CPUC in support of the
application.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 57
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The areas requested to be excluded from the revised scope of Phase III are
the most distant points from existing mains and present some of the most
challenging geographic conditions in the expansion area. Extension of mains to
serve the estimated 1,300 customers in the excluded areas would be considerably
more expensive than the service areas in Phases I and II. Furthermore, these
areas have significantly lower customer density than the remainder of the
expansion project; therefore, expected revenues would be insufficient to justify
the anticipated construction costs.
In August 1997, the Office of Ratepayer Advocates (ORA) for the CPUC filed
a protest to the Southwest application indicating that the terms of the original
agreement should be adhered to. Southwest responded with written comments in
support of its application. In September 1997, a prehearing conference was held
to discuss the filing, the ORA protest, and Southwest comments. The
administrative law judge (ALJ) made a preliminary ruling in favor of the ORA
protest, but allowed the parties an additional 20 days to supplement their
comments. During this time, Southwest and the ORA, pursuant to direction from
the CPUC, began to negotiate a settlement agreement, and the procedural schedule
was adjusted to allow the negotiations to continue beyond the 20-day period.
In January 1998, a settlement involving all parties to the proceeding was
executed and filed with the CPUC which redefined the terms and conditions for
completing the project and recovering the additional project costs. Although
CPUC approval of the settlement was still required, management anticipated
approval of the all-party settlement. In February 1998, a prehearing conference
was held before the ALJ and the assigned Commissioner for the purpose of taking
public comment on the settlement agreement. There was no opposition to the
settlement agreement from the Truckee Town Council at the conference, or in a
letter written by the Truckee town manager to the CPUC subsequent to the
conference.
Under the January 1998 proposed settlement, Southwest agreed, among other
things, to absorb $8 million in cost overruns experienced in Phase II of the
project. Southwest also agreed to an $11 million cost cap (with a maximum of
$3,800 per customer) for Phase III of the project. The Phase III project scope
would be modified as requested in the July 1997 application. In addition,
Southwest agreed not to file its next general rate case until the completion of
Phase III. Based on the proposed settlement, Southwest recognized an $8 million
pretax charge in the fourth quarter of 1997.
In May 1998, the ALJ issued an unexpected Proposed Decision (PD) rejecting
the January 1998 all-party settlement and directing Southwest to complete the
project under the terms and conditions of the 1995 certificate. A PD that
ignores an all-party settlement is rare and inconsistent with CPUC policies and
procedures established in 1992. Subsequent to the PD, the Truckee Town Council
took a formal position in opposition to the settlement, although they were not a
party to the proceeding, and had not previously opposed the settlement.
In July 1998, the CPUC voted to adopt the PD and reject the all-party
settlement, and ordered Southwest to proceed with all deliberate speed to
complete the project under the terms and scope of the 1995 certificate.
Southwest filed a Motion for Stay (Motion) of order and petitioned the CPUC for
rehearing (Petition) in August 1998. The CPUC stated in its order that Southwest
was required to show extraordinary circumstances to readjudicate the original
settlement. Because no evidentiary hearings were conducted, management did not
have the opportunity to demonstrate that such extraordinary circumstances exist;
however, it believes that such circumstances do exist. In September 1998, the
CPUC denied the Motion and in January 1999, the Petition was denied. As a
result, in February 1999, Southwest petitioned the Supreme Court of the State of
California for review of the July 1998 CPUC decision. Such a petition is
discretionary with the Supreme Court, and if accepted, could take up to two
years to be heard.
38
58 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
In September 1998, Southwest filed a civil lawsuit in the United States
Federal District Court naming the Town of Truckee as a defendant for an
indeterminate amount of damages. Southwest asserts that actions taken by the
Town of Truckee resulted in unanticipated changes in project scope, which
materially contributed to the cost overruns experienced during the construction
of Phase II of the project.
In November 1998, Southwest, together with representatives from the town of
Truckee, met before a federal mediator to reconcile the disputes and claims
against each other. As a result of the mediation, Southwest and representatives
of the town of Truckee are attempting to negotiate a Settlement Agreement and
Mutual Release (Agreement). If an Agreement is reached, it would need to be
ratified by the Truckee Town Council and approved by the CPUC, and likely would
address the civil suit against the town of Truckee, the remaining project scope,
and recovery of project costs among other items. An Agreement might also require
Southwest to postpone the filing of its next California general rate case. If an
Agreement is reached, it is anticipated that it will be presented to the Truckee
Town Council at a town meeting. If ratified by the Truckee Town Council,
Southwest would include the Agreement as part of a new application it plans to
file with the CPUC to reopen the prior California general rate case and
certificate proceeding in order to modify the original Settlement approved in
December 1994.
Management believes that subsequent events may reduce the remaining scope
and estimated costs of the project; however, preliminary estimates indicate that
it could cost an additional $23 million to $25 million to complete the project
under the terms of the 1995 certificate without modification. An additional
pretax write-off of up to $24 million could be recorded under this scenario.
This estimate is comprised of approximately $7 million related to costs incurred
through Phase II, and up to $17 million for the forecasted construction costs.
However, Southwest will actively pursue the described regulatory and legal
proceedings with the intent of reversing or mitigating the effects of the July
1998 CPUC action. Management believes that a reasonable possibility of modifying
the existing CPUC orders pertaining to the expansion project exists through
pursuit of the legal and regulatory remedies that have been outlined, although
there can be no assurance of a favorable outcome. As a result, Southwest has not
recorded any additional write-offs beyond the $8 million recognized in the
fourth quarter of 1997. Management also believes that civil litigation offers a
reasonable possibility of recovering certain amounts spent to deal with changes
in scope necessitated by unanticipated third party actions.
LNG STORAGE AND DISTRIBUTION SYSTEM. A subsidiary of the Company entered into an
agreement to build Liquefied Natural Gas (LNG) storage and distribution systems
to serve several small towns. The subsidiary contracted to provide project
management services, materials, two gas distribution systems, and two LNG
storage and vaporization systems. The project was completed in 1998. The total
project cost exceeded the contract price by approximately $5 million. A pretax
charge of $5 million was recorded in 1997 and was included in Other income
(deductions), net on the Consolidated Statements of Income.
NOTE 12.
ACQUISITION OF NORTHERN PIPELINE CONSTRUCTION CO.
In April 1996, the Company acquired all of the outstanding stock of
Northern Pipeline Construction Co. (Northern or the construction services
segment) pursuant to a definitive agreement dated November 1995. The Company
issued approximately 1,439,000 shares of common stock valued at $24 million in
connection with the acquisition. The acquisition was accounted for as a
purchase. Goodwill in the amount of approximately $10
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 59
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
million was recorded by Northern and is being amortized over 25 years. Northern
provides utility companies with trenching and installation, replacement, and
maintenance services for energy distribution systems.
During 1998, Northern recognized $38 million of revenues generated from
contracts with Southwest, and $36 million in 1997. During the period from the
acquisition date through December 31, 1996, the construction services segment
recognized $36 million of revenues generated from contracts with Southwest.
These revenues and associated profits are included in the consolidated financial
statements of the Company and were not eliminated during consolidation. SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation," provides that
intercompany profits on sales to regulated affiliates should not be eliminated
in consolidation if the sales price is reasonable and if future revenues
approximately equal to the sales price will result from the rate-making process.
Management believes these two criteria are being met. At December 31, 1998 and
1997, consolidated accounts receivable included $5 million and $3.6 million,
respectively, which were not eliminated during consolidation.
NOTE 13.
MERGER AGREEMENT WITH ONEOK, INC.
In December 1998, the Boards of Directors of the Company and ONEOK, Inc.
(ONEOK), headquartered in Tulsa, Oklahoma, announced a definitive agreement for
the Company to be merged into ONEOK. The agreement calls for ONEOK to pay cash
of $28.50 for each share of Company common stock outstanding. The transaction is
subject to customary conditions, including approvals from shareholders of the
Company and state regulators in Arizona, California, and Nevada. ONEOK expects
to account for the merger using the purchase method of accounting. If the merger
is consummated, the Company would operate as a division of ONEOK.
In connection with the proposed merger into ONEOK, the Company incurred
approximately $1.1 million (pretax) of financial advisor and legal costs, which
were included in Other income (deductions), net, during the fourth quarter of
1998. Additional amounts of financial advisor, legal, and accounting-related
expenses will be incurred during the merger process and, depending on the
successful completion of the merger, are estimated at $2 million to $5 million.
In February 1999, the Company announced that it had received an unsolicited
proposal from Southern Union Company (Southern Union), headquartered in Austin,
Texas, offering to acquire the Company for $32.00 per share in cash. The
proposal is preliminary in nature and subject to a number of contingencies and
uncertainties. Under the terms of the agreement with ONEOK, as a result of
certain preliminary determinations made by the Board of Directors of the
Company, the Board of Directors has authorized management to commence
substantive discussions with Southern Union regarding its proposal. No
assurances can be given that any agreement will be reached with Southern Union.
The merger agreement with ONEOK remains in full force and effect.
NOTE 14.
SEGMENT INFORMATION
The Company's operating segments are determined based on the nature of
their activities. The natural gas operations segment is engaged in the business
of purchasing, transporting, and distributing natural gas. Revenues are
generated from the sale and transportation of natural gas. The construction
services segment is engaged in the business of providing utility companies with
trenching and installation, replacement, and maintenance services for energy
distribution systems.
40
60 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The accounting policies of the reported segments are the same as those
described within Note 1 -- Summary of Significant Accounting Policies. Northern
accounts for the services provided to Southwest at contractual (market) prices.
The financial information pertaining to the Company's natural gas
operations and construction services segments for each of the three years in the
period ended December 31, 1998, is as follows (thousands of dollars):
1998
----------------------------------------------------------
Gas Construction
Operations Services Adjustments Total
- ----------------------------------------------------------------------------------------------------
Revenues from unaffiliated customers.... $ 799,597 $ 79,736 $ 879,333
Intersegment sales...................... -- 37,976 37,976
- ----------------------------------------------------------------------------------------------------
Total............................... $ 799,597 $117,712 $ 917,309
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Interest expense........................ $ 62,284 $ 1,070 $ 63,354
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Depreciation and amortization........... $ 80,231 $ 8,573 $ 88,804
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Income tax expense...................... $ 33,995 $ 2,419 $ 36,414
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment income.......................... $ 44,830 $ 2,707 $ 47,537
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment assets.......................... $1,772,418 $ 59,285 $(1,009) $1,830,694
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Capital expenditures.................... $ 179,361 $ 15,260 $ 194,621
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
1997
----------------------------------------------------------
Gas Construction
Operations Services Adjustments Total
- ----------------------------------------------------------------------------------------------------
Revenues from unaffiliated customers.... $ 614,665 $ 81,421 $ 696,086
Intersegment sales...................... -- 35,924 35,924
- ----------------------------------------------------------------------------------------------------
Total............................... $ 614,665 $117,345 $ 732,010
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Interest expense........................ $ 61,751 $ 1,467 $ 63,218
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Depreciation and amortization........... $ 74,528 $ 10,133 $ 84,661
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Income tax expense...................... $ 4,217 $ 642 $ 4,859
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment income.......................... $ 15,825 $ 644 $ 16,469
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment assets.......................... $1,717,025 $ 52,919 $(885) $1,769,059
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Capital expenditures.................... $ 164,528 $ 5,086 $ 169,614
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
1996
----------------------------------------------------------
Gas Construction
Operations Services Adjustments Total
- ----------------------------------------------------------------------------------------------------
Revenues from unaffiliated customers.... $ 546,361 $ 61,646 $ 608,007
Intersegment sales...................... -- 36,054 36,054
- ----------------------------------------------------------------------------------------------------
Total............................... $ 546,361 $ 97,700 $ 644,061
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 61
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1996
----------------------------------------------------------
Gas Construction
Operations Services Adjustments Total
- ----------------------------------------------------------------------------------------------------
Interest expense........................ $ 53,003 $ 1,910 $ 54,913
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Depreciation and amortization........... $ 67,443 $ 6,256 $ 73,699
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Income tax expense...................... $ 1,661 $ 2,213 $ 3,874
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment income.......................... $ 3,919 $ 2,655 $ 6,574
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Segment assets.......................... $1,498,099 $ 62,315 $(145) $1,560,269
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Capital expenditures.................... $ 210,743 $ 8,092 $ 218,835
- ----------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------
Construction services segment interest expense and income tax expense, for
the year ended December 31, 1996, include allocations of $968,000 and
$(387,000), respectively, from the gas operations segment. For the years ended
December 31, 1998 and 1997, no allocations from the gas operations segment to
the construction services segment were made.
Construction services segment assets include deferred tax assets of $1
million in 1998, $885,000 in 1997, and $145,000 in 1996, which were netted
against gas operations segment deferred tax liabilities during consolidation.
NOTE 15.
QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter Ended March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------------------------
(Thousands of dollars, except per share amounts)
1998
Operating revenues....................... $292,601 $192,897 $162,508 $269,303
Operating income (loss).................. 75,502 12,951 (529) 66,246
Net income (loss)........................ 35,953 (2,514) (10,945) 25,043
Basic earnings (loss) per common
share*................................. 1.31 (0.09) (0.38) 0.83
Diluted earnings (loss) per common
share*................................. 1.30 (0.09) (0.38) 0.82
1997
Operating revenues....................... $235,231 $136,938 $128,698 $231,143
Operating income (loss).................. 51,515 (3,982) (7,248) 61,976
Net income (loss)........................ 21,568 (12,748) (15,686) 23,335
Basic earnings (loss) per common
share*................................. 0.80 (0.47) (0.58) 0.85
Diluted earnings (loss) per common
share*................................. 0.80 (0.47) (0.58) 0.85
1996
Operating revenues....................... $188,352 $123,611 $125,255 $206,843
Operating income (loss).................. 38,539 (4,747) (8,404) 46,185
Net income (loss)........................ 14,859 (11,943) (14,638) 18,296
Basic earnings (loss) per common
share*................................. 0.60 (0.46) (0.55) 0.69
Diluted earnings (loss) per common
share*................................. 0.60 (0.46) (0.55) 0.68
* The sum of quarterly earnings (loss) per average common share may not equal
the annual earnings (loss) per share due to the ongoing change in the weighted
average number of common shares outstanding.
42
62 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The demand for natural gas is seasonal, and it is management's opinion that
comparisons of earnings for the interim periods do not reliably reflect overall
trends and changes in the Company's operations. Also, the timing of general rate
relief can have a significant impact on earnings for interim periods. See
Management's Discussion and Analysis for additional discussion of operating
results.
NOTE 16.
DISCONTINUED OPERATIONS -- FINANCIAL SERVICES ACTIVITIES
In July 1996, the Company completed the sale of the assets and liabilities of
PriMerit Bank (the Bank) to Norwest Corporation for $191 million. Proceeds from
the sale were used by the Company to retire debt incurred in connection with its
investment in the Bank. The loss on disposition was included in the 1995 results
of operations.