================================================================================
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 September 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 November 15, 1999
Common Stock, $3.75 par value 1,000 Shares
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SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 1999
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
Page
----
ITEM 1. Financial Statements
Condensed Consolidated Balance Sheets - September 30, 1999 and
December 31, 1998.......................................... 3
Condensed Consolidated Statements of Income - Three Months and
Nine Months Ended September 30, 1999 and 1998.............. 4
Condensed Consolidated Statements of Cash Flows - Nine Months
Ended September 30, 1999 and 1998.......................... 5
Notes to Condensed Consolidated Financial Statements.............. 6
ITEM 2. Management's Discussion and Analysis
of Financial Condition and Results
of Operations..................................................... 8
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
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
September 30, December 31,
1999 1998
-------------- -------------
(Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $ 2,390,548 $ 2,348,996
Less: accumulated provision for depreciation 780,016 727,624
-------------- -------------
1,610,532 1,621,372
Construction work-in-progress 86,617 55,670
-------------- -------------
1,697,149 1,677,042
-------------- -------------
Investments in subsidiaries and other property, net 62,461 34,022
-------------- -------------
Current Assets:
Cash and cash equivalents 19,825 15,197
Accounts receivable less provision for uncollectible accounts:
$4,379 -1999 and $3,461 -1998 110,405 114,380
Materials, supplies and fuel, at average cost 30,421 25,776
Other 5,362 2,692
-------------- -------------
166,013 158,045
-------------- -------------
Deferred Charges:
Regulatory tax asset 65,531 65,619
Other regulatory assets 73,791 61,675
Other 16,565 15,417
-------------- -------------
155,887 142,711
-------------- -------------
$ 2,081,510 $ 2,011,820
============== =============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 669,451 $ 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 728,871 606,450
-------------- -------------
1,519,937 1,389,432
-------------- -------------
Current Liabilities:
Short-term borrowings 65,100 105,000
Current maturities of long-term debt and preferred stock 421 30,473
Accounts payable 67,925 66,032
Accrued interest 12,470 7,535
Dividends declared 20,365 20,365
Accrued salaries and benefits 9,103 12,131
Other current liabilities 23,089 27,759
-------------- -------------
198,473 269,295
-------------- -------------
Deferred Credits:
Accumulated deferred federal income taxes 170,419 161,697
Accumulated deferred investment tax credit 36,471 37,944
Regulatory tax liability 37,846 38,939
Accrued Retirement Benefits 51,603 42,560
Customer advances for construction 38,361 34,961
Other 28,400 36,992
-------------- -------------
363,100 353,093
-------------- -------------
$ 2,081,510 $ 2,011,820
=============== =============
The accompanying notes are an integral part of the financial statements.
3
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands, Except Per Share Amounts)
Three-Months Ended Nine-Months Ended
September 30, September 30,
------------------------------- --------------------------
1999 1998 1999 1998
----------- ------------ ------------ ---------
(Unaudited) (Unaudited)
OPERATING REVENUES:
Electric $ 163,846 $ 157,250 $ 455,497 $ 434,558
Gas 13,056 13,394 69,934 66,872
Water 17,900 16,802 41,800 37,881
------------ ------------ ------------ ---------
194,802 187,446 567,231 539,311
------------ ------------ ------------ ---------
OPERATING EXPENSES:
Operation:
Purchased power 52,564 44,863 135,343 118,615
Fuel for power generation 32,560 32,842 85,397 84,169
Gas purchased for resale 9,603 9,887 46,978 42,727
Other 30,031 28,111 84,578 86,031
Maintenance 6,068 5,034 16,728 15,737
Depreciation and amortization 19,335 17,098 57,927 50,692
Taxes:
Income taxes 6,883 11,084 27,292 32,486
Other than income 5,231 4,901 14,851 14,782
------------ ------------ ------------ ---------
162,275 153,820 469,094 445,239
------------ ------------ ------------ ---------
OPERATING INCOME 32,527 33,626 98,137 94,072
------------ ------------ ------------ ---------
OTHER INCOME:
Allowance for other funds used during construction (2,451) 870 (2,451) 2,995
Other income - net (738) 366 (518) 213
------------ ------------ ------------ ---------
(3,189) 1,236 (2,969) 3,208
------------ ------------ ------------ ---------
Total Income 29,338 34,862 95,168 97,280
------------ ------------ ------------ ---------
INTEREST CHARGES:
Long-term debt 10,751 9,635 30,683 29,122
Other 2,082 1,834 6,965 5,502
Allowance for borrowed funds used during
construction and capitalized interest 1,647 (1,401) 1,214 (5,122)
------------ ------------ ------------ ---------
14,480 10,068 38,862 29,502
------------ ------------ ------------ ---------
INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES 14,858 24,794 56,306 67,778
Preferred dividend requirements of Company-
obligated mandatorily redeemable preferred
securities (1,043) (1,043) (3,128) (3,128)
------------ ------------ ------------ ---------
INCOME BEFORE PREFERRED DIVIDENDS 13,815 23,751 53,178 64,650
Preferred dividend requirements (1,365) (1,365) (4,094) (4,094)
------------ ------------ ------------ ---------
INCOME APPLICABLE TO COMMON STOCK $ 12,450 $ 22,386 $ 49,084 $ 60,556
============ ============ ============ =========
The accompanying notes are an integral part of the financial statements.
4
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Nine Months Ended
September 30,
-----------------------------------
1999 1998
--------- ---------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends $ 53,178 $ 64,650
Non-cash items included in income:
Depreciation and amortization 57,927 50,692
Deferred taxes and deferred investment tax credit 6,245 (1,167)
AFUDC and capitalized interest 3,665 (8,118)
Early retirement and severance amortization 3,145 3,196
Other 5,934 2,251
Changes in certain assets and liabilities:
Accounts receivable 3,975 4,885
Materials, supplies and fuel (4,645) (1,486)
Other current assets (2,670) (84)
Accounts payable 1,893 (8,212)
Other current liabilities (2,762) 18,823
Other - net (19,459) 2,682
--------- ---------
Net Cash Flows From Operating Activities 106,426 128,112
--------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES:
Additions to utility plant (95,487) (107,347)
Net customer refunds and contributions in aid construction 16,541 15,731
--------- ---------
Net cash used for utility plant (78,946) (91,616)
--------- ---------
Investments in subsidiaries and other property - net (28,394) (156)
--------- ---------
Net Cash Used In Investing Activities (107,340) (91,772)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
(Decrease) increase in short-term borrowings (41,703) 25,637
Proceeds from issuance of long-term debt 124,099 -
Reduction of long-term debt (31,758) (5,342)
Investment from the parent company 16,000 10,000
Dividends paid (61,096) (60,094)
--------- ---------
Net Cash Provided (Used) By Financing Activities 5,542 (29,799)
--------- ---------
Net increase in Cash and Cash Equivalents 4,628 6,541
Beginning balance in Cash and Cash Equivalents 15,197 6,920
--------- ---------
Ending balance in Cash and Cash Equivalents $ 19,825 $ 13,461
========= =========
Supplemental Disclosures of Cash Flow Information:
Cash Paid During Period For:
Interest $ 34,779 $ 28,530
Income Taxes $ 23,757 $ 27,385
The accompanying notes are an integral part of the financial statements.
5
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 nine month period ended
September 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.
NOTE 3. LONG TERM DEBT
- ------------------------
On July 12, 1999, $10 million of the Company's 6.86% medium term notes
matured. On July 16, 1999, $20 million of the Company's 6.83% medium term notes
matured.
On September 17, 1999, the Company issued $100,000,000 Floating Rate
Notes, due October 13, 2000. Interest on the Notes is payable quarterly in
arrears commencing on December 15, 1999. The interest rate on the Notes for each
interest period to maturity will be a floating rate, subject to adjustment every
three months, equal to the London InterBank Offered Rate for three-month U.S.
dollar deposits ("LIBOR") plus a spread of 0.75%. These Notes will not be
entitled to any sinking fund and will be redeemable without premium at the
option of the Company, in whole, beginning on March 15, 2000 and on the 15th day
of each month thereafter.
6
NOTE 4. 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
September 30, 1999 Electric Gas Water Consolidated
- -------------------- ------------- ------------- -------------- ------------
Operating Revenues $ 163,846 $ 13,056 $ 17,900 $ 194,802
============= ============= ============== ============
Operating income $ 25,685 $ (213) $ 7,055 $ 32,527
============= ============= ============== ============
Three Months Ended
September 30, 1998 Electric Gas Water Consolidated
- -------------------- ------------- ------------- -------------- ------------
Operating revenues $ 157,250 $ 13,394 $ 16,802 $ 187,446
============= ============= ============== ============
Operating income $ 28,348 $ (553) $ 5,831 $ 33,626
============= ============= ============== ============
Nine Months Ended
September 30, 1999 Electric Gas Water Consolidated
- -------------------- ------------- ------------- -------------- ------------
Operating Revenues $ 455,497 $ 69,934 $ 41,800 $ 567,231
============= ============= ============== ============
Operating income $ 76,970 $ 7,266 $ 13,901 $ 98,137
============= ============= ============== ============
Nine Months Ended
September 30, 1998 Electric Gas Water Consolidated
- ------------------ ------------- ------------- -------------- ------------
Operating revenues $ 434,558 $ 66,872 $ 37,881 $ 539,311
============= ============= ============== ============
Operating income $ 76,512 $ 7,691 $ 9,869 $ 94,072
============= ============= ============== ============
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information in this Form 10-Q 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 the Company'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 the
Company 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 the Company and Nevada Power Company and to
implement and realize anticipated cost savings from the recent merger with
Nevada Power; (6) industrial, commercial and residential growth in the
service territory of the Company; (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. The Company
assumes no obligation to update forward-looking statements to reflect
actual results, changes in assumptions or changes in other factors
affecting forward-looking statements.
8
RESULTS OF OPERATIONS
- ---------------------
The components of gross margin are set forth below (dollars in thousands):
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Operating Revenues:
Electric $ 163,846 $ 157,250 4.2% $ 455,497 $ 434,558 4.8%
Gas 13,056 13,394 -2.5% 69,934 66,872 4.6%
Water 17,900 16,802 6.5% 41,800 37,881 10.3%
------------ ------------ ----------- ------------ ------------ ------------
Total Revenues 194,802 187,446 3.9% 567,231 539,311 5.2%
Energy Costs:
Electric 85,124 77,705 9.5% 220,740 202,784 8.9%
Gas 9,603 9,887 -2.9% 46,978 42,727 9.9%
------------ ------------ ----------- ------------ ------------ ------------
Total Energy Costs 94,727 87,592 8.1% 267,718 245,511 9.0%
------------ ------------ ----------- ------------ ------------ ------------
Gross Margin 100,075 99,854 0.2% 299,513 293,800 1.9%
============ ============ =========== ============ ============ ============
Gross Margin by Segment:
Electric 78,722 79,545 -1.0% 234,757 231,774 1.3%
Gas 3,453 3,507 -1.5% 22,956 24,145 -4.9%
Water 17,900 16,802 6.5% 41,800 37,881 10.3%
------------ ------------ ----------- ------------ ------------ ------------
Total $ 100,075 $ 99,854 0.2% $ 299,513 $ 293,800 1.9%
============ ============ =========== ============ ============ ============
The causes for significant changes in specific lines comprising the results
of operations are as follows (dollars in thousands):
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Electric Operating Revenues:
Residential $ 41,892 $ 41,760 0.3% $ 127,903 $ 125,403 2.0%
Commercial 52,175 51,224 1.9% 141,874 135,094 5.0%
Industrial 47,878 48,020 -0.3% 139,793 137,771 1.5%
------------ ------------ ------------ ------------ ------------ ------------
Retail revenues 141,945 141,004 0.7% 409,570 398,268 2.8%
Other 21,901 16,246 34.8% 45,927 36,290 26.6%
------------ ------------ ------------ ------------ ------------ ------------
Total Revenues $ 163,846 $ 157,250 4.2% $ 455,497 $ 434,558 4.8%
============ ============ ============ ============ ============ ============
Retail sales in
megawatt-hours (MWH) 2,193,220 2,173,027 0.9% 6,332,985 6,143,241 3.1%
------------ ------------ ------------ ------------ ------------ ------------
Average retail revenue per MWH $ 64.72 $ 64.89 -0.3% $ 64.67 $ 64.83 -0.2%
Residential electric revenues increased for the three and nine months ended
September 30, 1999 due to a 2.7% increase in total customers over the prior
periods. The increase in revenues due to customer growth was almost entirely
offset by lower use per customer due to cooler weather for the three months
ended September 30, 1999.
9
Commercial electric revenues increased for the third quarter of this year
compared with the third quarter of 1998 due to a 3.0% increase in total
customers. Commercial revenues increased for the nine months ended September 30,
1999, due to a 3.1% increase in total customers and higher average use per
customer. Higher average use per customer resulted from the addition of larger
customers included in the commercial classification
Industrial electric revenues decreased slightly for the third quarter
compared to the prior year primarily due to lower use per customer for several
of the Company's gold mining customers. Industrial revenues increased for the
nine months ended September 30, 1999 due to customer growth that was partially
offset by lower use per customer. The reduction in use per customer for both
periods was the result of reduced production at several of the Company's gold
mining customers' facilities as a result of lower gold prices.
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's 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 third quarter of 1999 compared
to the prior year primarily due to a $8.7 million increase in wholesale electric
revenues. This increase was partially offset by a higher provision for customer
refunds during 1999. Other electric revenues were higher for the nine months
ended September 30, 1999 due to a $16.5 million increase in wholesale electric
sales. This increase was partially offset by a $4.3 million reclassification
from operating 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. Also, the increase in 1999 revenues was partially offset
by a higher provision for customer refunds and losses from the Company's Pinon
Pine subsidiaries.
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Gas Operating Revenues:
Residential $ 3,813 $ 3,506 8.8% $ 29,029 $ 28,032 3.6%
Commercial 2,189 2,198 -0.4% 15,338 15,301 0.2%
Industrial 1,781 1,960 -9.1% 7,899 8,529 -7.4%
Miscellaneous (194) 321 -160.4% 749 968 -22.6%
------------ ------------ ------------ ------------ ------------ ------------
Total retail revenue 7,589 7,985 -5.0% 53,015 52,830 0.4%
Wholesale revenue 5,467 5,409 1.1% 16,919 14,042 20.5%
------------ ------------ ------------ ------------ ------------ ------------
Total Revenues $ 13,056 $ 13,394 -2.5% $ 69,934 $ 66,872 4.6%
============ ============ ============ ============ ============ ============
Sales Decatherms (Dth):
Retail 1,248,372 1,285,076 -2.9% 9,269,549 9,346,123 -0.8%
Wholesale 2,440,570 3,229,436 -24.4% 7,988,902 7,811,885 2.3%
------------ ------------ ------------ ------------ ------------ ------------
Total 3,688,942 4,514,512 -18.3% 17,258,451 17,158,008 0.6%
------------ ------------ ------------ ------------ ------------ ------------
Average revenues per Dth
Retail $ 6.08 $ 6.21 -2.2% $ 5.72 $ 5.65 1.2%
Wholesale $ 2.24 $ 1.67 33.7% $ 2.12 $ 1.80 17.8%
Residential gas revenues were higher for the three and nine months ended
September 30, 1999 due to 4.4% and 4.2% increases in customers, respectively.
Revenues were also higher for the third quarter of 1999 because of higher use
per customer.
Commercial gas revenues for the three and nine months ended September 30,
1999 were comparable with the same periods in 1998. In both current year periods
presented, increased revenues from customer growth was offset by lower use per
customer. The lower use per customer for the nine months ended September 30,
1999 was the result of warmer weather during the first part of the year when gas
is used to heat.
10
Industrial gas revenues were lower for the three and nine months ended
September 30, 1998 due to lower use per customer as a result of warmer weather
early in 1999.
Wholesale gas revenues for the third quarter of 1999 were comparable with
the prior year. Wholesale revenues were higher for the nine months ended
September 30, 1999 due to several large gas sales contracts during the first
quarter of 1999.
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Water Operating Revenues $ 17,900 $ 16,802 6.5% $ 41,800 $ 37,881 10.3%
============ ============ ============ ============ ============ ============
Water revenues were higher for the third quarter of 1999 due mostly to a
5.9% increase in total customers. Water revenues increased for the nine months
ended September 30, 1999 compared to the prior year primarily due to a 4.4%
increase in total customers and higher use per customer as a result of less
precipitation during 1999.
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Purchased Power $ 52,564 $ 44,863 17.2% $ 135,343 $ 118,615 14.1%
Purchased Power MWH 1,542,282 1,155,726 33.4% 4,565,551 3,512,280 30.0%
Average cost per MWH
of Purchased Power $ 34.08 $ 38.82 -12.2% $ 29.64 $ 33.77 -12.2%
Purchased power costs were higher for the three and nine months ended
September 30, 1999 because the Company fulfilled more of its total energy
requirements with less expensive purchased power and reduced its own generation.
Purchased power costs were also higher during 1999 due to increased wholesale
sales. The higher costs were partially offset by lower average unit prices for
purchased power.
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Fuel for Power Generation $ 32,560 $ 32,842 -0.9% $ 85,397 $ 84,169 1.5%
MWHs generated 1,382,352 1,616,631 -14.5% 3,701,059 4,069,649 -9.1%
Average cost per MWH
of Generated Power $ 23.55 $ 20.32 15.9% $ 23.07 $ 20.68 11.6%
Fuel for generation costs for the three and nine months ended September 30,
1999, were comparable with the prior year despite 14.5% and 9.1% reductions in
electric generation, respectively. Higher gas prices and the absence of
Department of Energy co-funding of fuel costs at the Pinon Pine project
contributed to the higher average cost per MWH
11
of generated power. As discussed above, the Company was able to replace
electricity from generation with less expensive purchased power.
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Gas Purchased for Resale
Retail $ 5,043 $ 4,580 10.1% $ 32,048 $ 29,289 9.4%
Wholesale 4,560 5,307 -14.1% 14,930 13,438 11.1%
------------ ------------ ------------ ------------ ------------ ------------
Total 9,603 9,887 -2.9% 46,978 42,727 9.9%
============ ============ ============ ============ ============ ============
Gas Purchased for Resale Dth
Retail 1,248,575 1,254,356 -0.5% 9,273,542 9,383,733 -1.2%
Wholesale 2,440,570 3,226,962 -24.4% 7,988,902 7,811,885 2.3%
------------ ------------ ------------ ------------ ------------ ------------
Total 3,689,145 4,481,318 -17.7% 17,262,444 17,195,618 0.4%
============ ============ ============ ============ ============ ============
Average cost per Dth
Retail $ 4.04 $ 3.65 10.7% $ 3.46 $ 3.12 10.9%
Wholesale $ 1.87 $ 1.64 14.0% $ 1.87 $ 1.72 8.7%
The cost of retail gas purchased for resale increased for the three and
nine months ended September 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 Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Allowance for other funds
used during construction $ (2,451) $ 870 -381.7% $ (2,451) $ 2,995 -181.8%
Allowance for borrowed funds
used during construction (1,647) 1,401 -217.6% (1,214) 5,122 -123.7%
------------ ------------ ------------ ------------ ------------ ------------
$ (4,098) $ 2,271 -280.4% $ (3,665) $ 8,117 -145.2%
============ ============ ============ ============ ============ ============
Total allowance for funds used during construction (AFUDC) is lower for the
three and nine months ended September 30, 1999 because of construction completed
in June and December 1998 for the Pinon and Alturas projects, respectively.
Also, the 1999 amounts reflect an adjustment to reverse amounts previously
charged to AFUDC of $4.5 million. This adjustment resulted from a refinement of
amounts assigned to specific components of facilities that were completed in
different periods and used differing AFUDC rates.
12
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- -------------------
Change from Change from
1999 1998 Prior Year % 1999 1998 Prior Year %
------------ ------------ ------------ ------------ ------------ ------------
Other operating expense $ 30,031 $ 28,111 6.8% $ 84,578 $ 86,031 -1.7%
Maintenance expense 6,068 5,034 20.5% 16,728 15,737 6.3%
Depreciation and amortization 19,335 17,098 13.1% 57,927 50,692 14.3%
Income taxes 6,883 11,084 -37.9% 27,292 32,486 -16.0%
Interest charges- Long term debt 10,751 9,635 11.6% 30,683 29,122 5.4%
Interest charges-other 2,082 1,834 13.5% 6,965 5,502 26.6%
Other operating expense was higher for the third quarter of 1999 due to
higher claims reserves during the current year and adjustments that reduced
costs during 1998 related to stock compensation. Other operating expense was
slightly lower for the nine months ended September 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 for 1999 was partially
offset by higher claims reserves, rate case adjustments and other miscellaneous
items expensed during the current year.
Maintenance costs were higher for the three and nine months ended September
30, 1999 due to scheduled maintenance costs at the Valmy Unit 2 generating
facility.
Depreciation and amortization expense increased for the three months ended
September 30, 1999, due to the completion of the Alturas intertie in December
1998. Depreciation and amortization expense increased for the nine months ended
September 30, 1999, due to the completion of the Alturas intertie in December
1998 and the Pinon post-gasification facilities in June 1998.
Operating income taxes decreased for the three and nine months ended
September 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 nine months ended
September 30, 1999, because of a Public Utilities Commission of Nevada's
decision to assess partial interest on amounts payable in the 1997 earnings
sharing case and higher average short-term borrowing in 1999.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
During the first nine months of 1999, the Company earned $53.2 million in
income before preferred dividends. It declared $4.1 million in dividends to
holders of its preferred stock and declared $57.0 million in common stock
dividends to its parent, Sierra Pacific Resources.
Cash flows during the nine months ended September 30, 1999 decreased
slightly compared to the same period in 1998. Cash flows were less in 1999 due
to less cash provided from operating activities and more cash used for investing
activities. The decrease in cash flows from operating and investing activities
was partially offset by cash provided from financing activities. The decrease in
cash provided from operating activities was primarily due to cash utilized for
customer refunds and merger related cash requirements. 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.
Net cash provided by financing activities resulted from the issuance of $24
million of California rate reductions bonds in April 1999 and $100 million
floating rate notes issued on September 17, 1999. See "Regulatory Matters" for
more details regarding the California bonds.
13
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), $78.9 million (70.0%)
was spent as of September 30, 1999. Internally-generated funds provided 57.7% of
all construction expenditures.
On July 28, 1999, immediately following the consummation of the merger
between the Company's parent, Sierra Pacific Resources "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.
On October 1, 1999 Sierra Pacific Power Company provided Notice of
Redemption to the holders of Preferred Stock, Series A, $2.44 Dividend (4.88%),
Series B, $2.36 Dividend (4.72%) and Series C, $3.90 Dividend (7.80%). The
company paid $23.8 million on November 1, 1999 to effect the redemption. The
amount paid included the preferred stock par value of $23.1 million, a call
premium of $.4 million and accrued dividends of $.3 million.
Pinon Pine Power Project
- ------------------------
As reported in the Company's 1998 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. On November 2, 1999 the Company reached final
agreement with the DOE regarding the allowability of previously incurred natural
gas costs. The agreement also redefines the cooperative agreement performance
period and the responsibilities of both parties through the remainder of the
agreement. The period of performance is extended until January 1, 2001 or until
the facility is sold or operational control is transferred. The DOE agrees to
share past fuel costs and future natural gas costs used to fuel the gas
combustion turbine during periods when air extraction from the process is
directed to the gasifier island. In the agreement, the Company agreed to
undertake reasonable efforts to make the gasifier operational that include
capital improvements of $3.8 million, half of which will be funded by the DOE,
and a commitment to provide a defined level of operating expenses and other
engineering resources.
The Company is continuing in its efforts to obtain sustained operation of
the gasifier by identifying and redesigning problem areas.
Merger
- ------
On July 28, 1999 the merger between SPR and Nevada Power Company was
finalized.
On June 11, 1999, 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 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 last filing was submitted in October 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. The PUCN order also provided that any remaining gains
can be used to offset goodwill. After-tax gains may not be sufficient to offset
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 most of the generation facility sales will be completed by late-2000.
Following the issuance of the PUCN order on the merger, the Nevada
Legislature passed SB 438 which amended the restructuring process in Nevada.
Among other provisions, it required the utilities to provide last resort service
at a capped price, and provided that any shortfall experienced by the utilities
in revenues from the capped rates over experienced costs could be recovered from
the net gain from the generation divestiture. It is the utilities' position that
any
14
net gain must first be applied to any such shortfall; any remaining net gain may
then be used to offset stranded costs and then allocated to goodwill.
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.
Through September 30, 1999 the Company had incurred a total of $28.5
million in capitalized costs since merger work began. The capitalized amounts
consist of $17.3 million of transaction and transition costs and $11.2 million
of employee separation costs.
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, 1999, 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. On August 19, 1999, the PUCN approved a stipulation between the
Company, Staff, and the Utilities Consumer Advocate, which resulted in a $7.4
million and a $2.0 million refund to electric and gas customers, respectively.
Affiliate Transaction Rules and Affiliate Applications to Provide Potentially
Competitive Services
The Company and Nevada Power Company 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 were held June 28-30,1999. On August 31, 1999, the PUCN issued an order
denying the Companies' application. On September 15, 1999, the Companies filed a
Petition for Reconsideration of the PUCN's order denying the application.
15
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 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 operations 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.
During the hearing on the proposed past cost rule on June 1, 1999, the
PUCN determined that the impacts of SB 438 on existing and proposed electric
restructuring regulations should be evaluated. The PUCN issued Procedural Orders
13 and 14 and held workshops to discuss the impact of SB 438.
See the Company's Annual Report Form 10-K for more information
regarding the issues being considered as a result of restructuring of the
electric industry in Nevada. 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
16
days following a PUCN decision on Phases I and II and will include full proposed
tariffs for distribution service and all other noncompetitive services
On September 23, 1999, the PUCN issued an interim order on the
Company's Phase I Compliance Plan filing. The order contained the PUCN's
decision on revenue requirements, return on equity, depreciation, and the
unbundling study. The PUCN's decision establishes a new (lower) revenue
requirement for the vertically integrated electric utility that is based on a
return on equity rate of 10.25%, changes to generation and distribution
depreciation rates, other rate base and operating expense adjustments. The order
also establishes an electric distribution return on equity rate of 9.85% that
reflects a 40 basis point risk adjustment from the integrated electric utility.
The Company believes that SB 438 established the current revenue requirement for
the vertically integrated electric utility as present rate revenues. However,
the order denied the Company's motion to consider the impacts of SB 438 on the
Compliance Plan filing. The Company filed a Petition for Reconsideration and the
Phase II Compliance Plan filing on October 8, 1999.
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 Company and Nevada Power conducted informal workshops with the
appropriate parties to resolve issues related to Rules 9 (Line Extensions) and
15 (Non-Utility Generation Facilities) of the Distribution Open Access Tariffs.
Rule 9 provides for competition in line extension designs and construction while
Rule 15 provides procedures for the connection of non-utility generators. A
settlement was reached resolving Rule 15 and filed with the PUCN on June 18,
1999. Another settlement was reached resolving Rule 9 and was filed with the
PUCN on July 9th.
Past Costs
Past costs, which are commonly referred to as stranded costs in other
jurisdictions, 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. The final rule is expected to include the date for the submission of
filings to recover past costs, which will likely be 45 days after the order from
the compliance plan filing is issued.
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 has on this and other pending and adopted regulations. The PUCN has
scheduled a hearing on November 8, 1999, on the proposed past cost rule. 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 will be made late in 1999 or early 2000.
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. On March 16, 1999 the PUCN issued a revised proposed rule for PLR. A
hearing was held April 26, 1999. A new procedural final order was issued
regarding those matters.
The PUCN proposed PLR format requires the PLR functions to be performed
by a regulated affiliate of the Company and not by the electric distribution
utility. The business activities of the PLR affiliate must be limited to the PLR
function. The Company and Nevada Power filed joint comments which outlined
concerns that the PUCN proposed PLR format would not be financially viable. The
PUCN issued Procedural Order 11 to request comments on the financial viability
of the PUCN proposed PLR format.
17
SB 438 specifically provides for the electric distribution utility to
provide PLR services until July 1, 2001. The PUCN has scheduled a workshop on
November 8, 1999 on a new proposed rule for the PLR.
Independent Scheduling Administrator
The Company has participated in interim Independent Scheduling
Administrator (iISA) working groups which are developing iISA standards,
protocols and procedures. The PUCN issued a "Notice of Request for Comments and
Notice of Workshop" to hear from entities interested in performing the iISA
function, the timeline, the functions to be performed, the costs and how these
entities will adhere to the PUCN iISA principles. The PUCN held a workshop on
the proposed iISA on July 14, 1999. Presentations were made by the Mountain West
ISA and the California ISO. The workshop was continued on July 22, 1999.
On behalf of the Mountain West ISA, the Company and Nevada Power
submitted a filing to establish the ISA with the Federal Energy Regulatory
Commission ("FERC") on July 23, 1999. See "Regulatory Matters - FERC Matters-
Independent Scheduling Administrator (ISA)". The PUCN held a workshop to discuss
the adequacy of the ISA proposal.
On September 13, 1999, the Company and Nevada Power filed a brief on
recovery of ISA funding. On September 17, 1999, the PUCN issued a Procedural
Order setting the schedule for a hearing on the ISA filing. The PUCN identified
two issues for the hearing on October 25, 1999: ISA funding and pre-existing
contracts. The PUCN also requested parties to file a list of additional issues.
The Company and Nevada Power filed a response to the PUCN Procedural Order and
testimony for the hearing.
Meter and Data Exchange
The PUCN issued a Notice of Tariff Filing and Notice of Hearing on
meter and data exchange standards and protocols on September 23, 1999. The
hearing was held on October 27, 1999 and an order on the issue is pending.
Gas Restructuring
To comply with Nevada AB 366 for natural gas deregulation, the PUCN is
developing new natural gas rules. To develop new rules, the PUCN is following
similar processes as in electric restructuring.
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 re-issued the proposed rule and held hearings in
March and June. The PUCN is expected to adopt the proposed rule at its next
agenda meeting.
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 non-bypassable, 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
18
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.
FERC Matters
Alturas
On April 15, 1999 the FERC approved the settlement in the Import Limit
Case which had previously been certified by the Administrative Law Judge 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 on
Regional Transmission Organizations (RTOs). The FERC proposed characteristics of
an RTO and also the requirement for utilities to form or join RTOs.
Merger
19
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 an update of its transmission rates
(also proposed by the companies).
On May 17/th/, TDPUD filed a Petition for Rehearing of the FERC's order
approving the merger. TDPUD claims the FERC violated its own policy by allowing
the merger to be consummated prior to divestiture of generation assets. The
Company and Nevada Power filed an answer to TDPUD's Petition for Rehearing in
May. On July 14, 1999, the FERC denied in all aspects TDPUD's petition.
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. The hearing will commence on
January 25, 2000.
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.
Motions to intervene and protest in the Company's generation tariffs
rate case were due on April 20, 1999. Newmont, City of Fallon, and TDPUD filed
motions to intervene and protest. Barrick (a mining company) filed a motion to
intervene with comments. Several other parties also filed interventions. The
PUCN filed motion to intervene and protest one day after the date established by
the FERC. The PUCN requested the FERC to hold the proceedings in abeyance to
allow the PUCN more time to review Sierra's divestiture plan filing.
The Company filed an Answer to the protests filed on the tariff on
May 5, 1999. In response to the PUCN request, the Company requested that the
FERC rule on the Company's tariff by November 30, 1999 (rather than September
30, 1999) to allow the PUCN more time. The Company also provided clarification
in response to other protests.
On July 20, 1999, the Company filed a motion to expedite the FERC's
consideration of the tariff. The motion requested that the FERC approve the
tariff by September 30, 1999 since the PUCN issues were resolved.
Independent Scheduling Administrator (ISA)
On July 23, 1999, the Company and Nevada Power submitted a filing to
establish the Mountain West ISA (Docket ER97-3719). The proposal centers on the
formation of an interim ISA called Mountain West ISA, which will ensure the non-
discriminatory treatment of transmission customer in two wholesale electricity
markets; one in northern Nevada and one in southern Nevada. The formation of the
ISA is viewed as an interim step in the move to broader regional restructuring
of the electric service industry in the western United States.
Fifteen parties filed to intervene in the ISA filing. On September 17,
1999, the Company, Nevada Power and the Mountain West ISA filed answers to the
protests filed on the ISA filing. The California ISO filed an answer to the
Company's and Nevada Power's response to their protest on September 28, 1999.
Year 2000 Issues
- ----------------
20
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 implementing 100% of its mission
critical 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.
The Company participated in the North American Electric Reliability
Council's (NERC) September 9, 1999 nation-wide readiness drill for utilities.
The purpose of the drill was to test alternative lines of communications by
simulating loss of data and voice communications, and to train and prepare staff
for the millennium date rollover. The Company experienced a few minor procedural
problems, that have since been corrected.
In September 1999, the Company completed an independent audit conducted
by Sargent and Lundy (S&L). In summary the S&L final report stated, "During the
course of the audit, S&L discovered no evidence to indicate that mission
critical systems at selected power stations would not perform as expected...."
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, 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.
All Company contingency plans were completed as of September 30, 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.
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.
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. 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 $4.0 million was incurred through September
30, 1999.
22
Approximately $2.5 million of the expenditures relate to business
systems, and $1.5 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
1998 Annual Report on Form 10-K.
23
PART II
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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 nine month
period ended September 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: November 15, 1999 By /s/ Mark A. Ruelle
--------------------- ---------------------------------
Mark A. Ruelle
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: November 15, 1999 By /s/ Mary O. Simmons
--------------------- ---------------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
25