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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
- ----
ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED June 30, 1999
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
Commission File Number 0-508
SIERRA PACIFIC POWER COMPANY
(Exact name of registrant as specified in its charter)
NEVADA 88-0044418
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P.O. Box 10100 (6100 Neil Road)
Reno, Nevada 89520-0400
(89511)
(Address of principal executive office) (Zip Code)
(775) 834-4011
(Registrant's telephone number, including area code)
Indicate by check mark whether registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date.
Class Outstanding at August 13, 1998
Common Stock, $3.75 par value 1,000 Shares
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1
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED JUNE 30, 1999
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
Page
-----
ITEM 1 . Financial Statements
Report of Independent Accountants................................................................ 3
Condensed Consolidated Balance Sheets June 30, 1999 and
December 31, 1998........................................................................... 4
Condensed Consolidated Statements of Income - Three Months and Six Months
Ended June 30, 1999 and 1998................................................................ 5
Condensed Consolidated Statements of Cash Flows - Six Months
Ended June 30, 1999 and 1998................................................................ 6
Notes to Condensed Consolidated Financial Statements............................................. 7
ITEM 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations.................................................................................... 9
ITEM 3. Quantitative and Qualitative Disclosures about
Market Risk...................................................................................... 23
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings................................................................................ 24
ITEM 5. Other Information................................................................................ 24
ITEM 6. Exhibits and Reports on Form 8-K................................................................. 24
Signature Page............................................................................................. 25
2
INDEPENDENT ACCOUNTANTS' REPORT
To the Board of Directors and Stockholder of
Sierra Pacific Power Company
- ----------------------------
Reno, Nevada
We have reviewed the accompanying condensed consolidated balance sheet of Sierra
Pacific Power Company (the "Company") and subsidiaries as of June 30, 1999, and
the related condensed consolidated statements of income and cash flows for the
three-month and six-month periods ended June 30, 1999 and 1998. These financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and of making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in
accordance with generally accepted auditing standards, the objective of which is
the expression of an opinion regarding the financial statements taken as a
whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet and consolidated statement of
capitalization of Sierra Pacific Power Company and subsidiaries as of December
31, 1998, and the related consolidated statements of income, common
shareholder's equity, and cash flows for the year then ended (not presented
herein); and in our report dated January 29, 1999, (February 12, 1999 as to
Notes 1 and 3) we expressed an unqualified opinion on those consolidated
financial statements. In our opinion, the information set forth in the
accompanying condensed consolidated balance sheet as of December 31, 1998, is
fairly stated, in all material respects, in relation to the consolidated balance
sheet from which it has been derived.
DELOITTE & TOUCHE LLP
Reno, Nevada
August 5, 1999
3
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
June 30, December 31,
1999 1998
--------------- ---------------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,374,322 $ 2,348,996
Less: accumulated provision for depreciation 762,799 727,624
------------- ------------
1,611,523 1,621,372
Construction work-in-progress 75,141 55,670
------------- ------------
1,686,664 1,677,042
------------- ------------
Investments in subsidiaries and other property, net 63,435 34,022
============= ============
Current Assets:
Cash and cash equivalents 6,503 15,197
Accounts receivable less provision for uncollectible accounts:
$4,313 -1999 and $3,461 -1998 102,506 114,380
Materials, supplies and fuel, at average cost 29,829 25,776
Other 2,559 2,692
------------- ------------
141,397 158,045
------------- ------------
Deferred Charges:
Regulatory tax asset 65,531 65,619
Other regulatory assets 61,888 61,675
Other 14,936 15,417
------------- ------------
142,355 142,711
------------- ------------
$ 2,033,851 $ 2,011,820
============= ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 668,000 $ 661,367
Preferred stock 73,115 73,115
Preferred stock subject to mandatory redemption:
Company-obligated mandatorily redeemable preferred securities of the
Company's subsidiary Sierra Pacific Power Capital I, holding
solely $50 million principal amount of 8.6% junior
subordinated debentures of the Company, due 2036 48,500 48,500
Long-term debt 629,919 606,450
------------- ------------
1,419,534 1,389,432
------------- ------------
Current Liabilities:
Short-term borrowings 123,000 105,000
Current maturities of long-term debt and preferred stock 30,485 30,473
Accounts payable 50,011 66,032
Accrued interest 7,580 7,535
Dividends declared 15,165 20,365
Accrued salaries and benefits 13,154 12,131
Other current liabilities 24,772 27,759
------------- ------------
264,167 269,295
------------- ------------
Deferred Credits:
Accumulated deferred federal income taxes 165,906 161,697
Accumulated deferred investment tax credit 36,961 37,944
Regulatory tax liability 37,846 38,939
Accrued Retirement Benefits 45,977 42,560
Customer advances for construction 36,462 34,961
Other 26,998 36,992
------------- ------------
350,150 353,093
------------- ------------
$ 2,033,851 $ 2,011,820
============= ============
The accompanying notes are an integral part of the financial statements.
4
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
Three-Months Ended Six-Months Ended
June 30, June 30,
------------------------------ ------------------------------
1999 1998 1999 1998
------------ ------------ -------------- ------------
(Unaudited) (Unaudited)
OPERATING REVENUES:
Electric $147,348 $135,169 $291,651 $277,308
Gas 18,851 22,112 56,878 53,478
Water 13,619 11,862 23,900 21,079
-------- -------- -------- --------
179,818 169,143 372,429 351,865
-------- -------- -------- --------
OPERATING EXPENSES:
Operation:
Purchased power 42,111 35,377 82,779 73,752
Fuel for power generation 26,367 27,447 52,837 51,327
Gas purchased for resale 12,658 13,510 37,375 32,841
Other 30,765 29,092 54,547 57,920
Maintenance 5,164 6,007 10,660 10,703
Depreciation and amortization 19,498 16,672 38,592 33,593
Taxes:
Income taxes 8,597 8,742 20,409 21,402
Other than income 4,821 4,988 9,620 9,881
======== ======== ======== ========
149,981 141,835 306,819 291,419
-------- -------- -------- --------
OPERATING INCOME 29,837 27,308 65,610 60,446
-------- -------- -------- --------
OTHER INCOME:
Allowance for other funds used during construction - 1,155 - 2,126
Other income - net 213 (275) 220 (153)
-------- -------- -------- --------
213 880 220 1,973
-------- -------- -------- --------
Total Income 30,050 28,188 65,830 62,419
-------- -------- -------- --------
INTEREST CHARGES:
Long-term debt 10,071 9,720 19,932 19,487
Other 2,280 1,759 4,883 3,668
Allowance for borrowed funds used during construction and
capitalized interest (236) (2,039) (434) (3,721)
-------- -------- -------- --------
12,115 9,440 24,381 19,434
-------- -------- -------- --------
INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES 17,935 18,748 41,449 42,985
Preferred dividend requirements of Company-obligated
mandatorily redeemable preferred securities (1,043) (1,043) (2,086) (2,086)
-------- -------- -------- --------
INCOME BEFORE PREFERRED DIVIDENDS 16,892 17,705 39,363 40,899
Preferred dividend requirements (1,365) (1,365) (2,730) (2,730)
-------- -------- -------- --------
INCOME APPLICABLE TO COMMON STOCK $ 15,527 $ 16,340 $ 36,633 $ 38,169
======== ======== ======== ========
The accompanying notes are an integral part of the financial statements.
5
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Six Months Ended
June 30,
--------------------------------------------
1999 1998
---------------- ----------------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends $ 39,363 $ 40,899
Non-cash items included in income:
Depreciation and amortization 38,592 33,593
Deferred taxes and deferred investment tax credit 2,222 (1,579)
AFUDC and capitalized interest (434) (5,846)
Early retirement and severance amortization 2,096 2,109
Other non-cash (158) 1,427
Changes in certain assets and liabilities:
Accounts receivable 11,874 16,570
Materials, supplies and fuel (4,053) (871)
Other current assets 133 (1,190)
Accounts payable (16,021) (5,371)
Other current liabilities (1,919) 3,664
Other - net (8,034) 36
------------- ------------
Net Cash Flows From Operating Activities 63,661 83,441
------------- ------------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (55,708) (66,454)
Net customer refunds and contributions in aid construction 9,474 10,319
------------- ------------
Net cash used for utility plant (46,234) (56,135)
------------- ------------
(Investments in) disposal of subsidiaries and other property - net (29,385) 98
------------- ------------
Net Cash Used In Investing Activities (75,619) (56,037)
------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings 17,731 14,037
Proceeds from issuance of long-term debt 23,696 -
Reduction of long-term debt (233) (5,188)
Investment from the parent company 8,000 5,000
Dividends paid (45,930) (40,730)
------------- ------------
Net Cash Used In Financing Activities 3,264 (26,881)
------------- ------------
Net (decrease) increase in Cash and Cash Equivalents (8,694) 523
Beginning balance in Cash and Cash Equivalents 15,197 6,920
------------- ------------
Ending balance in Cash and Cash Equivalents $ 6,503 $ 7,443
============= ============
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 26,138 $ 25,178
Income Taxes $ 13,522 $ 36,588
The accompanying notes are an integral part of the financial statements.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
NOTE 1. MANAGEMENT'S STATEMENT
- ---------------------------------
In the opinion of the management of Sierra Pacific Power Company,
hereafter referred to as the Company, the accompanying unaudited interim
condensed consolidated financial statements contain all adjustments (consisting
of only normal recurring adjustments) necessary to present fairly the condensed
consolidated financial position, condensed consolidated results of operations
and condensed consolidated cash flows for the periods shown. These condensed
consolidated financial statements do not contain the complete detail or footnote
disclosure concerning accounting policies and other matters which are included
in full year financial statements and therefore, they should be read in
conjunction with the Company's audited financial statements included in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998.
The results of operations for the three and six month period ended June 30,
1999 are not necessarily indicative of the results to be expected for
the full year.
Principles of Consolidation
---------------------------
The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries, Sierra Pacific Power Capital I, Pinon Pine
Corp., and Pinon Pine Investment Co. The Company accounts for its ownership of
GPSF-B, a Delaware corporation acquired in February 1999, using the equity
method because the Company intends to own the entity temporarily. All
significant intercompany transactions and balances have been eliminated in
consolidation.
Reclassifications
-----------------
Certain items previously reported for years prior to 1999 have been
reclassified to conform to the current year's presentation. Net income and
shareholder's equity were not affected by these reclassifications.
NOTE 2. RECENT PRONOUNCEMENTS OF THE FASB
- -------------------------------------------
In June 1998, the Financial Accounting Standards Board issued SFAS 133,
entitled "Accounting for Derivative Instruments and Hedging Activities". This
statement establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts (collectively referred to as derivatives), 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. In May 1999, members of the Financial Accounting
Standards Board agreed to delay the effective date of Statement 133 to fiscal
years beginning after June 15, 2000. The Company is still assessing the impact
of SFAS 133 on its financial condition and results of operations.
7
NOTE 3. SEGMENT INFORMATION
- -----------------------------
The Company operates three business segments providing regulated electric,
natural gas and water service. Electric service is provided to northern Nevada
and the Lake Tahoe area of California. Natural gas and water services are
provided in the Reno-Sparks area of Nevada.
Information as to the operations of the different business segments is set
forth below based on the nature of products and services offered. The Company
evaluates performance based on several factors, of which the primary financial
measure is business segment operating income. Intersegment revenues are not
material.
Financial data for business segments is as follows (in thousands).
Three Months
Ended June 30, 1999 Electric Gas Water Consolidated
- ---------------------- ------------ ------------ ----------- ------------
Operating Revenues $ 147,348 $ 18,851 $ 13,619 $ 179,818
============ ============ ============ ============
Operating income $ 24,601 $ 1,189 $ 4,047 $ 29,837
============ ============ ============ ============
Three Months
Ended June 30, 1998 Electric Gas Water Consolidated
- ---------------------- ------------ ------------ ----------- ------------
Operating revenues $ 135,169 $ 22,112 $ 11,862 $ 169,143
============ ============ ============ ============
Operating income $ 21,546 $ 2,947 $ 2,815 $ 27,308
============ ============ ============ ============
Six Months
Ended June 30, 1999 Electric Gas Water Consolidated
- ---------------------- ------------ ------------ ----------- ------------
Operating Revenues $ 291,651 $ 56,878 $ 23,900 $ 372,429
============ ============ ============ ============
Operating income $ 51,285 $ 7,479 $ 6,846 $ 65,610
============ ============ ============ ============
Six Months
Ended June 30, 1998 Electric Gas Water Consolidated
- ---------------------- ------------ ------------ ----------- ------------
Operating revenues $ 277,308 $ 53,478 $ 21,079 $ 351,865
============ ============ ============ ============
Operating income $ 47,962 $ 8,110 $ 4,374 $ 60,446
============ ============ ============ ============
8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information in this Form 10-K includes forward-looking statements
within the meaning of the Private Securities Litigation Reform Act of
1995. These forward-looking statements relate to anticipated financial
performance, management's plans and objectives for future operations,
business prospects, outcome of regulatory proceedings, market conditions
and other matters. Words such as "anticipate," "believe," "estimate,"
"expect," "intend," "plan" and "objective," and other similar expressions
identify those statements which are forward-looking. These statements are
based on management's beliefs and assumptions and on information currently
available to management. Actual results could differ materially from those
contemplated by the forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with
such statements, factors that could cause SPPC's actual results to differ
materially from those contemplated in any forward-looking statement
include, among others, the following: (1) the pace and extent of the
ongoing restructuring of the electric and gas industries in Nevada and
California; (2) the outcome of regulatory and legislative proceedings and
operational changes related to industry restructuring; (3) the amount SPPC
is allowed to recover from its customers for certain costs which prove to
be uneconomic in the new competitive market; (4) the outcome of ongoing
and future regulatory proceedings; (5) management's ability to integrate
the operations of SPPC and Nevada Power Company and to implement and
realize anticipated cost savings from the Merger; (6) industrial,
commercial and residential growth in the service territory of SPPC; (7)
fluctuations in electric, gas and other commodity prices and the ability
to manage such fluctuations successfully; (8) changes in the capital
markets and interest rates affecting the ability to finance capital
requirements; (9) the loss of any significant customers; (10) the ability
to lessen the risk of the impact of the Year 2000 on internal and external
computer and software systems; and (11) the weather and other natural
phenomena. Other factors and assumptions not identified above may also
have been involved in deriving these forward-looking statements, and the
failure of those other assumptions to be realized, as well as other
factors, may also cause actual results to differ materially from those
projected. SPPC assumes no obligation to update forward-looking statements
to reflect actual results, changes in assumptions or changes in other
factors affecting forward-looking statements.
9
RESULTS OF OPERATIONS
- ---------------------
The components of gross margin are set forth below (dollars in thousands):
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Operating Revenues:
Electric $147,348 $135,169 9.0% $291,651 $277,308 5.2%
Gas 18,851 22,112 -14.7% 56,878 53,478 6.4%
Water 13,619 11,862 14.8% 23,900 21,079 13.4%
------------ ------------ ------------ ------------ ------------ ------------
Total Revenues 179,818 169,143 6.3% 372,429 351,865 5.8%
Energy Costs:
Electric 68,478 62,824 9.0% 135,616 125,079 8.4%
Gas 12,628 13,510 -6.5% 37,375 32,841 13.8%
------------ ------------ ------------ ------------ ------------ ------------
Total Energy Costs 81,106 76,334 6.3% 172,991 157,920 9.5%
------------ ------------ ------------ ------------ ------------ ------------
Gross Margin 98,712 92,809 6.4% 199,438 193,945 2.8%
============ ============ ============ ============ ============ ============
Gross Margin by Segment:
Electric 78,870 72,345 9.0% 156,035 152,229 2.5%
Gas 6,223 8,602 -27.7% 19,503 20,637 -5.5%
Water 13,619 11,862 14.8% 23,900 21,079 13.4%
------------ ------------ ------------ ------------ ------------ ------------
Total $ 98,712 $ 92,809 6.4% $199,438 $193,945 2.8%
============ ============ ============ ============ ============ ============
The causes for significant changes in specific lines comprising the results
of operations are as follows (dollars in thousands):
Three Months Six Months
Ended June 30, Ended June 30,
-------------- -------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Electric Operating Reveunes:
Residential $ 38,486 $ 37,117 3.7% $ 86,011 $ 83,643 2.8%
Commercial 46,294 42,068 10.0% 89,699 83,870 7.0%
Industrial 46,548 45,758 1.7% 91,915 89,750 2.4%
------------ ------------ ------------ ------------ ------------ ------------
Retail revenues 131,328 124,943 5.1% 267,625 257,263 4.0%
Other 16,020 10,226 56.7% 24,026 20,045 19.9%
------------ ------------ ------------ ------------ ------------ ------------
Total Revenues $ 147,348 $ 135,169 9.0% $ 291,651 $ 277,308 5.2%
============ ============ ============ ============ ============ ============
Retail sales in
megawatt-hours (MWH) 2,045,998 1,945,699 5.2% 4,139,765 3,970,214 4.3%
------------ ------------ ------------ ------------ ------------ ------------
Average retail revenue per MWH $ 64.19 $ 64.21 0.0% $ 64.65 $ 64.80 -0.2%
Residential revenues increased for the three months and six months ended
June 30, 1999 due to a 2.4% increase in total customers over the prior periods
and to a lesser extent higher use per customer.
10
Commercial revenues increased for the second quarter of this year compared
with the second quarter of 1998 primarily due to higher use per customer.
Higher average use per customer resulted from the addition of larger customers
included in the commercial classification. Commercial revenues increased for
the six months ended June 30, 1999, also due to higher use per customer and a
total increase in customers of 2.8%.
Industrial revenues increased slightly for the second quarter compared to
the prior year primarily due to a 1.1% increase in customers. Industrial
revenues increased for six months ended June 30, 1999 due to customer growth
and, to a lesser extent, higher use per customer. The increase in use per
customer was primarily due to increased production at two of the Company's large
gold mining customers' facilities.
As reported in the Company's 1998 10-K, gold production costs vary greatly
at Nevada mines, along with profitability. Mining reports indicate many of
Nevada mines have a production cost of less than $300 per ounce, with some
larger mines producing within the $192 to $240 per ounce range. When compared
to world production costs, Nevada is well below the worldwide average of $262
per ounce. While Nevada's gold mines have the lowest costs in the world,
investments in exploration and development have fallen, and may continue to
fall. In addition, low gold prices may also shorten the expected mine lives of
certain Nevada properties as lower grade ore becomes uneconomic to mine.
Other electric revenues were higher in the second quarter of 1999 compared
to the prior year primarily due to a $5.8 million increase in wholesale electric
revenues. Other electric revenues were higher for the six months ended June 30,
1999 due to a $7.8 million increase in wholesale electric sales. This increase
was partially offset by a $4.3 million reclassification from operating expense
to revenues reflecting a customer refund that resulted from a decision by the
Public Utilities Commission of Nevada.
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Gas Operating Reveunes:
Residential $ 8,273 $ 8,457 -2.2% $ 25,216 $ 24,527 2.8%
Commercial 4,311 4,458 -3.3% 13,149 13,102 0.4%
Industrial 2,391 2,721 -12.1% 6,118 6,569 -6.9%
Miscellaneous 412 312 32.1% 943 647 45.7%
------------ ------------ ------------ ------------ ------------ ------------
Total retail revenue 15,387 15,948 -3.5% 45,426 44,845 1.3%
Wholesale revenue 3,464 6,164 -43.8% 11,452 8,633 32.7%
------------ ------------ ------------ ------------ ------------ ------------
Total Revenues $ 18,851 $ 22,112 -14.7% $ 56,878 $ 53,478 6.4%
============ ============ ============ ============ ============ ============
Sales Decatherms (Dth):
Retail 2,621,342 2,810,977 -6.7% 8,021,177 8,061,047 -0.5%
Wholesale 1,797,396 3,334,923 -46.1% 5,548,332 4,582,449 21.1%
------------ ------------ ------------ ------------ ------------ ------------
Total 4,418,738 6,145,900 -28.1% 13,569,509 12,643,496 7.3%
------------ ------------ ------------ ------------ ------------ ------------
Average revenues per Dth
Retail $ 5.87 $ 5.67 3.5% $ 5.66 $ 5.56 1.8%
Wholesale $ 1.93 $ 1.85 4.3% $ 2.06 $ 1.88 9.6%
Residential and commercial revenues were lower for the second quarter of
1999 compared to the same period in 1998 due to lower usage per customer
resulting from warmer weather in Northern Nevada during 1999. This reduction in
revenues was partially offset by increases in customers of 4.0% and 4.2%,
respectively. Residential and commercial revenues increased for the six months
ended June 30, 1999 compared to the prior year because of a 4.0% increase in
customers for both customer classifications. The increase in revenues was
partially offset by lower use per customer as a result of warmer weather in
1999.
11
Industrial revenues were lower for the three and six months ended June 30,
1998 due to lower use per customer as a result of warmer weather in 1999.
Wholesale gas revenues were lower for the second quarter of 1999 compared
to the prior year due to less wholesale opportunities. Wholesale revenues were
higher for the six months ended June 30, 1999 due to several large gas contracts
during the first quarter of 1999.
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Water Operating Revenues $13,619 $11,862 14.8% $23,900 $21,079 13.4%
============ ============ ============ ============ ============ ============
Water revenues were higher for the second quarter of 1999 due mostly to
increased use per customer resulting from warmer weather and less precipitation
during 1999. A 3.4% increase in customers during 1999 also contributed to
higher revenues during the second quarter. Water revenues increased for the six
months ended June 30, 1999 compared to the prior year for the same reasons that
second quarter 1999 earnings were higher. A price increase effective April 2,
1999 also contributed to higher year to date revenues in 1999.
Three Months Six Months
Ended June 30, Ended June 30,
---------------- ----------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Purchased Power $ 42,111 $ 35,377 19.0% $ 82,779 $ 73,752 12.2%
Purchased Power MWH 1,703,474 1,168,352 45.8% 3,023,269 2,356,554 28.3%
Average cost per MWH
of Purchased Power $ 24.72 $ 30.28 -18.4% $ 27.38 $ 31.30 -12.5%
Purchased power costs were higher for the three and six months ended June
30, 1999 because of increased retail and wholesale electric revenues as
discussed previously and as a result of a generation outage. The higher costs
were partially offset by lower average unit prices for electricity.
Three Months Six Months
Ended June 30, Ended June 30,
---------------- ----------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Fuel for Power Generation $ 26,367 $ 27,447 -3.9% $ 52,837 $ 51,327 2.9%
MWHs generated 1,146,340 1,223,265 -6.3% 2,318,707 2,453,018 -5.5%
Average cost per MWH
of Generated Power $ 23.00 $ 22.44 2.5% $ 22.79 $ 20.92 8.9%
12
Fuel for generation costs were lower for the second quarter of 1999 because
of a longer than anticipated plant outage for scheduled maintenance. Fuel for
generation costs increased for the six months ended June 30, 1999 because of
higher gas unit prices and the absence of Department of Energy co-funding of
fuel costs at the Pinon Pine project. However, the increase in fuel for
generation costs was partially offset by lower coal prices and reduced
generation due to the plant outage discussed previously.
Three Months Six Months
Ended June 30, Ended June 30,
---------------- ----------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Gas Purchased for Resale
Retail $ 9,444 $ 7,808 21.0% $ 27,005 $ 24,709 9.3%
Wholesale 3,214 5,702 -43.6% 10,370 8,132 27.5%
------------ ------------ ------------ ------------ ------------ ------------
Total 12,658 13,510 -6.3% 37,375 32,841 13.8%
============ ============ ============ ============ ============ ============
Gas Purchased for Resale Dth
Retail 2,621,426 2,881,142 -9.0% 8,024,967 8,129,377 -1.3%
Wholesale 1,797,396 3,337,397 -46.1% 5,548,332 4,584,923 21.0%
------------ ------------ ------------ ------------ ------------ ------------
Total 4,418,822 6,218,539 -28.9% 13,573,299 12,714,300 6.8%
============ ============ ============ ============ ============ ============
Average cost per Dth
Retail $ 3.60 $ 2.71 32.8% $ 3.37 $ 3.04 10.9%
Wholesale $ 1.79 $ 1.71 4.7% $ 1.87 $ 1.77 5.6%
The cost of retail gas purchased for resale increased for the three and six
months ended June 30, 1999 because of considerably higher gas unit prices. The
increase in gas unit prices is attributable to increased demand for gas in the
Pacific Northwest and additional transportation fees.
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Allowance for other funds
used during construction $ - $1,155 -100.0% $ - $2,126 -100.0%
Allowance for borrowed funds
used during construction 236 2,039 -88.4% 434 3,721 -88.3%
------------ ------------ ------------ ------------ ------------ ------------
$ 236 $3,194 -92.6% $ 434 $5,847 -92.6%
============ ============ ============ ============ ============ ============
Total allowance for funds used during construction (AFUDC) is lower for the
three and six months ended June 30, 1999 because of construction completed in
June and December 1998 for the Pinon and Alturas projects, respectively. The
current AFUDC rate calculation results in the entire amount being reflected as
borrowed funds in 1999.
13
Three Months Six Months
Ended June 30, Ended June 30,
-------------- --------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Other operating expense $30,765 $29,092 5.8% $54,547 $57,920 -5.8%
Maintenance expense 5,164 6,007 -14.0% 10,660 10,703 -0.4%
Depreciation and amortization 19,498 16,672 17.0% 38,592 33,593 14.9%
Income taxes 8,597 8,742 -1.7% 20,409 21,402 -4.6%
Interest charges-other 2,280 1,759 29.6% 4,883 3,668 33.1%
Other operating expense was higher for the second quarter of 1999 due higher
claims reserves during the current year and adjustments that reduced costs
during 1998 related to stock compensation and the water rate case decision.
Operating expense was primarily lower for the six months ended June 30, 1999 due
to a reclassification of $4.3 million from expense to a contra-revenue in order
to reflect a refund resulting from the 1997 earnings sharing decision by the
Public Utilities Commission of Nevada. The decrease in costs was partially
offset by the costs increases that occurred in the second quarter of 1999 as
described above.
Maintenance costs were lower for the second quarter of 1999 because of lower
program costs to replace electric insulators during the current year.
Maintenance costs for the six months ended June 30, 1999 were comparable with
prior year amounts.
Depreciation and amortization expense increased for the three and six months
ended due to the completion of the Alturas intertie in December 1998 and Pinon
post-gasification facilities closed to plant in June 1998.
Operating income taxes decreased for the three and six months ended June 30,
1999 due to lower operating income before income taxes and a lower effective tax
rate during the current year.
Interest charges-other were higher for the three and six months ended June
30, 1999 because of a Public Utilities Commission of Nevada's decision to assess
partial interest to amounts payable in the 1997 earnings sharing case and higher
short-term borrowing in 1999.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
During the first six months of 1999, the Company earned $39.4 million in
income before preferred dividends. It declared $2.7 million in dividends to
holders of its preferred stock and declared $38 million in common stock
dividends to its parent, Sierra Pacific Resources.
Cash flows during the six months ended June 30, 1999 decreased compared to
the same period in 1998. Cash flows were less in 1999 due to less cash provided
from operating activities, more cash used for investing activities. The
decrease in current year cash flows was partially offset by cash provided from
financing activities during the current year. The decrease in cash provided
from operating activities was primarily due to cash utilized for customer
refunds and financing costs paid in connection with the merger. The increase in
cash used for investing activities was due to the Company's acquisition of
General Electric Capital Corporation's interest in Pinon Pine Company L.L.C.
GPSF-B. Cash provided by financing activities resulted from the issuance of
California rate reductions bonds. See the Regulatory Matters section for more
details regarding the California bonds.
14
Construction Expenditures and Financing
- ---------------------------------------
The Company's construction program and capital requirements for the period
1999-2003 were originally discussed in the Company's 1998 Annual Report on Form
10-K. Of the amount projected for 1999 ($112.7 million), $46.2 million (41.0%)
had been spent as of June 30, 1999. Internally-generated funds exceeded all
construction expenditures.
On July 28, 1999, immediately following the consummation of the merger
between SPR and Nevada Power Company, the Company put into place a $150 million
unsecured revolving credit facility with Mellon Bank, N.A., as Administrative
Agent, First Union National Bank and Wells Fargo Bank, N.A., as Syndication
Agents, and certain other participating banks. This facility may be used for
working capital and general corporate purposes, including for commercial paper
backup, and replaced all existing credit facilities of the Company. At the same
time, the Company revised its existing commercial paper program.
Pinon Pine Power Project
- ------------------------
As reported in its Annual Report on Form 10K, the Company has been in
dispute with the DOE concerning funding of the remaining $14 million under the
cooperative agreement and the allowance of previously incurred natural gas fuel
cost paid by the DOE. Negotiations have been occurring and a partial settlement
has been reached. The DOE has agreed to resume funding of the O&M costs as well
as fuel charges incurred during startup of the gasifier. On July 26, 1999, the
DOE transferred $2.7 million for O&M and fuel charges for the period January
through May 1999. The Company is still in negotiations regarding the natural
gas charges incurred while the gasifier was not operational. The negotiations
should be finalized by the end of the third quarter, 1999.
The Company is continuing in its efforts to obtain sustained operation of
the gasifier by identifying and redesigning problem areas.
On July 28, 1999, immediately following the consummation of the merger
between SPR and Nevada Power Company, the Company put into place a $150 million
unsecured revolving credit facility with Mellon Bank, N.A., as Administrative
Agent, First Union National Bank and Wells Fargo Bank, N.A., as Syndication
Agents, and certain other participating banks. This facility may be used for
working capital and general corporate purposes, including for commercial paper
backup, and replaced all existing credit facilities of the Company. At the same
time, the Company revised its existing commercial paper program.
Merger
- ------
On July 28, 1999 the merger between the Company's parent (Sierra Pacific
Resources) and Nevada Power Company was finalized.
Following approvals from the Department of Justice (April 16, 1999) and the
SEC (expiration of comment period on June 8, 1999), the PUCN gave unanimous
approval, on June 11, 1999, of a stipulation between the merging companies, PUCN
staff and the Utility Consumer Advocate, regarding the merging companies' joint
divestiture plan. As part of the stipulation, the companies were required to
re-file the divestiture plan and file the final Independent System Administrator
(ISA) proposal with the PUCN and the Federal Energy Regulatory Commission
(FERC). The filings were submitted in July 1999. The PUCN merger order
provides that upon selling the generating units, both companies can determine
how they will use the proceeds of the sales, up to the book value of the plants.
Any after-tax gains above book value will be used to offset stranded costs, as
determined by the PUCN. Any remaining gains can be used to offset goodwill.
After-tax gains may not be sufficient to cover goodwill. However, if the
combined Company demonstrates that the divestiture "resulted in a market for
generation services that produced market prices that are lower than what could
have been achieved otherwise, the combined Company may include in the general
rate a request to recover goodwill." The Company expects that the generation
sales will be completed by late-2000.
Under terms of the stipulation, the merged company is required to file a
general rate case three years after the start of retail competition in the state
of Nevada that would give the merged company the opportunity to recover costs of
the merger, provided the merged company can demonstrate that merger savings
exceed merger costs. Merger costs are to be split among the non-competitive,
potentially competitive and unregulated services or businesses. An opportunity
to recover the non-competitive portion of the merger costs will be addressed in
the rate case that follows the start of competition in Nevada. The burden is on
the merged Company to prove that merger savings exceed merger costs. The merged
company will also have the opportunity to recover goodwill in the same
proceeding.
15
Through June 30, 1999 the Company had incurred a total of $11.2 million in
capitalized costs since merger work began.
Note: See Regulatory Matters - Electric Restructuring Activities,
------------------- ---------------------------------
regarding Senate Bill 438, and its impact on the merged company and generation
divestiture.
Regulatory Matters
- ------------------
Nevada Matters
Earnings Sharing --------------
- ----------------
In February 1997, the PUCN approved a rate plan that provided for a 50/50
sharing between customers and Company shareholders of electric and gas utility
earnings in excess of a 12 percent return on average equity. In lieu of
refunds, the Company has an opportunity, subject to certain conditions, to apply
excess earnings toward buying out of long-term fuel and purchased power
contracts. The earnings sharing agreement applies to each of the three years
ending December 31, 1999, 1998 and 1997.
On April 21, the PUCN approved refunds of $8.0 million in electric and $1.5
in gas, plus interest, for the 1997 earnings sharing case. The gas refund
reflects the PUCN's acceptance of the Company's recommendation to apply $ 0.4
million of the refund to offset the variable interest receivable balance. The
PUCN deferred its decision on several issues which could result in an additional
$ 1.5 million of refunds in the 1997 earnings sharing case. The Company had
originally requested to refund $ 7.3 million for electric and $ 1.7 million for
gas. All amounts are provided for in the financial statements.
On April 30, 1999, the Company filed an earnings sharing request, based on
1998 earnings, of $7.0 million for electric customers and $1.9 million for gas
customers. The Company reached a tentative settlement on this issue with the
staff of the PUCN in July 1999.
Affiliate Transaction Rules and Affiliate Applications to Provide Potentially
Competitive Services
The Company and Nevada Power filed a joint motion to set aside or modify
the affiliate transaction rules adopted by the PUCN on January 14, 1999. The
companies requested the PUCN to modify the rules related to name/logo, sharing
services, sharing officers and directors, and transfer pricing. To date the
PUCN has not acted on this motion. On March 30, 1999 the Company and Nevada
Power filed with the District Court a "Complaint and Petition for Declaratory
and Injunctive Relief and for Judicial Review" relating to the Affiliate
Transaction Rules. The companies asked that the court find that the rules
"violate plaintiff's federal and state constitutional guarantees, are unlawful
and invalid because they were enacted in violation of the procedural and
substantive provisions of the Administrative Procedures Act, and are unlawful
and invalid because they exceed the authority of the PUCN and are unsupported by
the evidence." The companies asked that the court order the PUCN "to cease and
desist from enforcing the regulations." There has been no action in the court
case.
The PUCN issued an order consolidating the merging companies applications
for authorization to provide potentially competitive services, and hearings
began on June 28, 1999. The PUCN order is expected in the third quarter.
16
Electric Restructuring Activities
In July 1997, the Governor of Nevada signed into law Assembly Bill 366
(AB366) which provides for competition to be implemented in the electric utility
industry in the state no later than December 31, 1999. However, in early
February 1999, the PUCN recommended to the state legislature that the start date
for competition be delayed to allow more time for consideration of issues as a
result of restructuring. On April 19, 1999, the Nevada Senate passed SB438,
which is an amendment to AB366. In July 1999 the Governor of Nevada signed
SB438 into law. The new law, contingent upon the completion of the SPR/NPC
merger, contains the following provisions:
. Adds metering and billing as potentially competitive services.
. Changes start date for competition to March 1, 2000; any decision to further
delay the start date to be made by the governor, not the PUCN.
. Electric distribution utility is the Provider of Last Resort (PLR) until
alternate methods go into effect.
. Sets PLR rates at existing rates, except that Nevada Power may submit one
more deferred energy case before October 1, 1999; PLR may reduce rates below
this level.
. Only the PLR may request a reduction in its rates during the period March 1,
2000 through March 1, 2003.
. Allows the use of the net proceeds of generation divestiture to pay for any
reduction in PLR rates below the cap described above, during the period March
1, 2000 to March 1, 2003.
. Repeals deferred energy for electric on October 1, 1999.
. Permits alternative sellers to submit bids to provide PLR service after July
1, 2001, subject to a PUCN public interest finding and a PUCN-held auction.
. Requires utilities to comply with terms of existing purchase power
obligations; specifies criteria for recovery of purchase power costs;
prevents PUCN from direct or indirect action to modify or terminate any
purchase power obligation.
. If utility purchases generation from a divested unit for PLR service the PUCN
cannot impute a value of the generation unit other than the sales price of
the unit.
. PUCN must consider in determining recoverable costs, the failure of a utility
to minimize income tax effect of gains and losses of assets and obligations.
. PUCN must include in recoverable costs any reasonable costs incurred by the
utility for severance, early retirement, and related items.
. Allows affiliates providing potentially competitive services to use name and
logo of utility.
. SB 438 does not impair rights under existing electric service contracts or
labor agreements.
. Utilities may enter into contracts with customers prior to March 1, 2000;
specifies that alternative sellers may aggregate two or more customers;
prohibits PUCN from limiting ability of alternative sellers to aggregate
customers and for customers to form groups for aggregation.
. Allows the PUCN to use "hearing officers" to conduct hearings.
The following are highlights of recent restructuring activity:
Compliance Plan (Dockets 99-4001/4002)
On April 1, 1999, the Company filed Phase I, the revenue requirements and
unbundling study portions, of the Restructuring Compliance Filing with the PUCN.
The filing includes the development of electric revenue requirements for the
test period 1998. In the unbundling study, the revenue requirements were
assigned and allocated to a number of service components including generation,
aggregation, transmission, distribution, metering, billing, and customer
services. On April 30, 1999, the Company filed Phase II, which included the
proposed bundled rate design. Phase III will be filed 15 days following a PUCN
decision on Phases I and II and will include full proposed tariffs for
distribution service and all other noncompetitive services. Intervenors will be
17
required to file testimony or alternative proposals at the same time. The
hearings were held July 26th through August 2nd.
Distribution Open Access Tariffs
On January 7, 1999, the PUCN issued an order adopting a final rule for
distribution tariffs (adopted as a temporary regulation). On February 1, 1999
the Company filed proposed language for distribution tariffs and filed testimony
in support of its distribution tariffs filing on March 9, 1999. On April 9,
1999 a stipulation resolving most issues and agreeing to further filings on
unresolved issues was filed with the PUCN.
The merging companies conducted informal workshops with the appropriate
parties to resolve issues related to Rules 9 (Line Extensions) and 15 (Nom-
Utility Generation Facilities) of the Distribution Open Access Tariffs.
Settlements resolving both were reached and filed with the PUCN.
Past Costs
Past costs, which are commonly referred to as stranded costs in other
jurisdictions, will continue to be addressed in 1999. AB366 permits the
recovery of generation costs pursuant to specified legal criteria. The PUCN has
conducted several workshops on past costs in which various topics were
discussed, including the characteristics that define recoverable past costs,
criteria for evaluating the effectiveness of mitigation efforts, options for
cost recovery mechanisms and applicable tax and accounting issues.
On April 8, 1999, the PUCN issued a revised proposed rule that specifies
the information a utility must include in its request for recovery of past
costs. On June 1, 1999, the PUCN began and suspended the hearing on the proposed
past cost rule. Due to the passage of SB 438, the PUCN determined that this
rule and other regulations should be evaluated to investigate the impact of SB
438. The Company has not completed an estimate of its past costs, since such a
calculation is dependent on a variety of issues related to restructuring which
are not resolved at this time. These rules are expected to be completed and any
required past cost filing to be made by the end of 1999.
Provider of Last Resort
The provider of last resort (PLR) will provide electric service to
customers who do not select an electricity provider and to customers who are not
able to obtain service from an alternative seller after the date competition
begins. SB 438 specifically provides for the electric distribution utility to
provide PLR services until July 1, 2001. The proposed PLR rule will be included
in the evaluation of SB 438 impacts addressed in Procedural Order 13.
Gas Restructuring
To comply with Nevada AB 366 for natural gas deregulation, the PUCN is
developing new natural gas rules. The PUCN is following similar processes as in
electric restructuring to develop new rules.
Gas Licensing
On January 7, 1998, the PUCN issued an order adopting a final rule for
licensing which was adopted as a temporary regulation.
On February 9, 1999, the PUCN issued a proposed rule for gas licensing
fees. On March 23, 1999 the PUCN held a workshop on the proposed rule for
licensing fees for alternative sellers. The hearing, also scheduled for this
day, was postponed. The PUCN will re-issue the proposed rule and hold hearings
at a later date.
18
California Matters
------------------
Rate Reduction Bonds
California's electricity restructuring statute (Assembly Bill 1890, Chapter
854, California Statutes of 1996, as amended), permits California investor-owned
utilities, including the Company, to finance the recovery of a reduction in
electricity rates for residential and small commercial customers through the
issuance of rate reduction certificates. Transition costs consist of the costs
of generation-related assets and obligations that may become uneconomic as a
result of a competitive generation market, together with certain other costs
associated therewith.
In order for the Company to recover transition and associated costs, the
California Public Utilities Commission (CPUC) authorized the establishment of
nonbypassable, usage-based, per kilowatt hour charges ("FTA Charges") to be
included in the regular utility bills of residential and small commercial
consumers located in the historical service territory of the Company in
California. The right to receive payments made in respect of the FTA Charges is
referred to as Transition Property.
On April 9, 1999, The Company sold the Transition Property to SPPC Funding
LLC, a Delaware special purpose limited liability company whose sole member is
the Company, in exchange for the proceeds of the SPPC Funding LLC Notes, Series
1999-1 (the "Underlying Notes"). SPPC Funding LLC then issued and sold the
Underlying Notes to the California Infrastructure and Economic Development Bank
Special Purpose Trust SPPC-1 (the "Trust") in exchange for the proceeds of the
sale of the Trust's $24.0 million 6.4% Rate Reduction Certificates, Series 1999-
1 (the "Certificates"). The Trust, which had been established by the California
Infrastructure and Economic Development Bank, issued and sold the Certificates
in a private placement pursuant to Rule 144A under the Securities Act of 1933,
as amended. The Certificates are one of a series of rate reduction certificates
that may be issued from time to time by the Trust and sold to investors upon
terms determined at the time of sale.
Revenue Cycle Unbundling
On February 18, 1999, the CPUC approved the Company's proposed Revenue
Cycle Services Credits (RCSC) application filed February 2, 1998. The RCSC
addresses meter ownership, meter services, meter reading, and billing and
applies to customers who select their own provider of a revenue cycle service.
On April 9, 1999, the Company made a compliance tariff filing which reflects the
approved credits.
Direct Access Tariffs
On April 5, 1999, the CPUC approved the Company's compliance filing,
effective back to March 18, 1998, which proposed tariff changes to implement
direct access.
Rate Unbundling
On April 5, 1999, the CPUC approved the Company's proposed unbundled
rates effective back to June 1, 1998.
Distribution Competition
The CPUC has opened a docket item to solicit comments and proposals on
distributed generation and competition in electric distribution service. It is
too early to determine how this proceeding may affect the Company.
Generation Divestiture
- ----------------------
The Company has filed with the CPUC its request for approval to sell its
generation plants.
19
FERC Matters
------------
Alturas
On April 15, 1999 the FERC approved the settlement in the Import Limit Case
which had previously been certified by the ALJ in June 1998. The settlement
provides for a continuation of the current import limit allocation until the
Alturas intertie is in service. At that time and until February 28, 2001,
Truckee Donner Public Utility District (TDPUD) will receive 30 MW of import
capability. After February 28, 2001, allocation of import capacity will be
determined by the FERC based on the results of the Company's 1998 Resource Plan
and a subsequent filing with the FERC in 1999.
Regional Transmission Organizations
On May 13, 1999, the FERC issued a Notice of Proposed Rulemaking
(NOPR) on Regional Transmission Organizations (RTOs). The FERC proposed
characteristics of an RTO and also the requirement for utilities to form or join
RTOs.
Merger
On April 14, 1999, the FERC voted to approve the merger of SPR, the Company
and Nevada Power, as proposed. In approving the merger the FERC required the
companies to divest of their generation facilities (as proposed by the
companies) and required Nevada Power to file for an update its transmission
rates (also proposed by the companies). On July 14, 1999 the FERC denied
TDPUD's rehearing request re the FERC approval.
Transmission Rate Case
On March 30, 1999, the Company filed with the FERC to increase its open
access transmission rates. The Company requested an increase of $16 million in
the annual revenue requirement for network service. The point-to-point rate
would increase from $ 2.80 /kW-mo. to $ 3.21 /kW-mo. This filing incorporates
the Alturas intertie, completed in December 1998, and the reclassification of
transmission and distribution facilities approved by the PUCN last summer.
On May 28, 1999, as expected, the FERC issued an order setting the rate
case for hearing. The proposed rates are accepted subject to refund and
suspended until November 1, 1999. On June 14, 1999, as required by the May 28
order, the Company filed additional information on the proposed transmission and
distribution (T&D) reclassification. The Company also requested that the FERC
accept the filing and approve the T&D split. On July 29, 1999 the FERC accepted
the Company's proposed T&D reclassification.
Generation Tariffs
On March 31, 1999, the Company filed Docket No. ER99-2332 with the FERC for
approval of generation tariffs that contain the rates, terms and conditions
under which the new owners of the Company's generation would operate after
divestiture. The tariffs permit market-based rates after the offering of
capacity under a cost-based recourse approach.
After motions to intervene protesting the Company's filing were filed by
several entities, the Company, on May 5, 1999, filed an answer to the protests.
On July 20, 1999 the Company filed a motion to expedite FERC's consideration of
the tariff. Consistent with the Nevada merger "Joint Proposal", the Company
requested that the FERC approve the tariff by September 30, as the PUCN issues
have been resolved.
20
Year 2000 Issues
- ----------------
To the maximum extent permitted by applicable law, the following
information is being designated as a "Year 2000 Readiness Disclosure" pursuant
to the "Year 2000 Information and Readiness Disclosure Act" which was signed
into law on October 19, 1998.
The Company uses business application software programs and relies on
computing infrastructure that includes embedded systems that have a Year 2000
(Y2K) affect on the Company. In many cases, the Company's software programs and
embedded systems use two-digit years that may recognize a date using `00' as the
year 1900 rather than the year 2000. This could result in the computer or device
shutting down, performing incorrect computations, or performing in an
inconsistent manner.
In 1996 the Company established its Y2K project to address Y2K issues. The
project's scope includes: (1) business application systems (including, but not
limited to, customer information and billing) and financial systems (including
time reporting, payroll, general ledger, accounts payable and purchasing, and
end-user developed systems) (2) embedded systems (including equipment that
operates or controls operating facilities such as power plants, electric
transmission and distribution, water, gas, telecommunications, and information
technology systems); (3) customer, vendor, and supplier relationships and (4)
testing and contingency planning.
To implement its Y2K strategies, the Company established a Y2K project
office currently headed by the Chief Financial Officer. This office includes an
oversight committee representing all lines of business, and a "champions team"
representing electric generation, transmission and distribution, gas
distribution, water production and distribution, telecommunications, systems
control, computer infrastructure and building facilities. Also represented are
internal audit, engineering, procurement, legal, and human resources. In
addition, the Company has utilized the expertise of outside consultants to
assist in the project management and the technical aspects of the project.
Business Application Systems
The initial focus for the Y2K project team was on the business application
systems. In the fall of 1996 the Company purchased software assessment tools and
completed its inventory and code assessment for its mainframe business systems.
The inventory is comprised of over 7 million lines of COBOL code, and end-user
programs.
The Company developed and strictly adheres to a Y2K methodology that
includes unit, system wide and Y2K date specific testing.
The Company has successfully completed implemented 100% of its business
systems.
Embedded Systems
The Company hired an outside engineering consultant, Network Systems
Engineering Corporation (NSEC), to assist the Company's staff in conducting a
thorough and comprehensive inventory of its embedded systems at the component
level. All systems have been inventoried and assessed. This inventory identified
over 2,500 potentially date sensitive items. The Company and NSEC have contacted
all manufacturers of those components that they have identified as critical to
operations and continues to contact other manufacturers of embedded system
components to determine if their components are Y2K ready. As of June 30, 1999,
100% of the Company's mission critical embedded systems are Y2K ready.
The Company's Y2K readiness activities are tracked and reported monthly to
the North American Electric Reliability Council (NERC), an association comprised
of all segments of the electric industry. NERC expects utilities to have
completed all Y2K testing and remediation by June 30, 1999. The Company has met
that expectation and has filed a letter with NERC expressing its readiness.
21
Vendors and Suppliers
The Company has contacted in writing all vendors and suppliers of products
and services that it considers critical to its operations. These contacts have
included, but were not limited to, suppliers of interstate transportation
capacity for coal supplies, natural gas producers, financial institutions, and
telephone service providers. The Company has met one on one with several of its
critical vendors and suppliers to assess their Y2K readiness. From these
meetings, the Company feels that these vendors and suppliers have a viable Y2K
program and that they will meet their commitments to the Company. If it becomes
necessary, the Company may consider new business and procurement alternatives
for products and services as necessary to the extent that alternatives are
available.
Major Customers
The Company has met face to face with many of its major customers to share
its progress on Y2K. Also discussed at these meetings is the customer's Y2K
readiness. The Company will continue to keep its major customers informed as to
its progress on Y2K remediation, testing and contingency planning.
Contingency Planning
The Company's Y2K strategies include contingency planning for both business
and embedded systems. The planning effort includes critical Company areas such
as electric generation, water, gas, telecommunications, building facilities,
information technology, networks, vendors and suppliers, and operations
personnel. Quick action response teams and additional Company personnel are
planned to be available for the century rollover. Additionally, the Company's
Emergency Operations Center (EOC) will be activated for the century rollover.
Generation, Systems Control, and Transmission/Distribution contingency plans are
complete. The remaining Company plans will be complete by the end of September,
1999.
As part of its normal business practice, the Company maintains plans to
follow during emergency circumstances, some of which could arise from Y2K
problems. Presently, the Company continues to develop and refine its
contingency plans for potential Y2K related problems.
Potential Risks
With respect to its internal operations, those over which the Company has
direct control, the Company believes the most significant potential risks from
Y2K problems are: (1) its ability to use electronic devices to control and
operate its generation, gas, water, telecommunication, transmission and
distribution systems; (2) its ability to render timely bills to its customers;
and (3) the ability to maintain continuous operations of its computer systems.
The Company depends upon external parties, including customers, suppliers,
business partners, gas and electric system operators, government agencies, and
financial institutions to reliably deliver their products and services. The
Company believes that its most reasonable likely worst case scenario is the
extent to which any of these parties experiences Y2K problems in their system.
Should any of these critical vendors fail, the impact of any such failure could
become a significant challenge to the Company's ability to meet the demands of
its customers. Business continuity interruption could also have a material
adverse financial impact, including but not limited to, lost sales revenues,
increased operating costs, and claims from customers related to business
interruptions. Based upon the information supplied to date by our critical
vendors and suppliers, the Company believes the probability of such failures is
low. The Company is monitoring the progress of these critical entities and
contingency plans are being developed to address the potential failure of an
external party to be Y2K ready.
22
Financial Implications
With 100% of mission critical components tested, findings indicate that the
transition through critical Y2K dates is expected to have minimal impact on the
Company's Electric, Gas, and Water operations. These results are reflected in
reduced costs discussed below.
The Company currently estimates that its total incremental expenditures for
the Y2K effort, since it began identification of Y2K cost, will be approximately
$5.9 million, through December 1999. This estimate has been reduced from
amounts previously reported based on updated assessments of the project costs.
Y2K costs include assessment, remediation, testing and contingency planning
activities. Of the total project costs, about $3.7 million has been incurred
through June 30, 1999. Approximately $2.4 million of the expenditures relate to
business systems, and $1.3 million relate to the Company's embedded systems.
The Company anticipates that the remaining expenditures will be spent on
remediating non-mission critical systems, and equipment necessitated by the
contingency plans.
The Company's Y2K program is progressing and the Company believes it is
taking all reasonable steps necessary to be able to operate successfully through
and beyond the turn of the century.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
There have been no material changes to the information previously disclosed
regarding quantitative and qualitative market risk in the Company's Annual
Report on Form 10K.
23
PART II
-------
ITEM 1. LEGAL PROCEEDINGS
None.
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits filed with this Form 10-Q.
(27) The Financial Data Schedule containing summary financial
information extracted from the condensed consolidated financial
statements filed on Form 10-Q for the six month period ended June
30, 1999, for Sierra Pacific Power Company and is qualified in
its entirety by reference to such financial statements.
(b) Reports on Form 8-K
None
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Sierra Pacific Power Company
-------------------------------
(Registrant)
Date: August 11, 1999 By /s/ Mark A. Ruelle
----------------------------- ------------------------------
Mark A. Ruelle
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: August 11, 1999 By /s/ Mary O. Simmons
------------------------------ ------------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
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