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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 March 31, 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 May 14, 1999
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 MARCH 31, 1999
CONTENTS
PART I - FINANCIAL INFORMATION
------------------------------
Page
-----
ITEM 1. Financial Statements
Report of Independent Accountants................................ 3
Condensed Consolidated Balance Sheets - March 31, 1999 and
December 31, 1998........................................... 4
Condensed Consolidated Statements of Income - Three Months
Ended March 31, 1999 and 1998............................... 5
Condensed Consolidated Statements of Cash Flows - Three Months
Ended March 31, 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...................................................... 19
PART II - OTHER INFORMATION
---------------------------
ITEM 1. Legal Proceedings................................................ 20
ITEM 5. Other Information................................................ 20
ITEM 6. Exhibits and Reports on Form 8-K................................. 20
Signature Page............................................................. 21
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 and subsidiaries as of March 31, 1999, and the related
condensed consolidated statements of income and cash flows for the three-month
periods ended March 31, 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, retained earnings,
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
April 30, 1999
3
SIERRA PACIFIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
March 31, December 31,
1999 1998
---------- ------------
Unaudited)
ASSETS
Utility Plant at Original Cost:
Plant in service $2,364,329 $2,348,996
Less: accumulated provision for depreciation 745,863 727,624
---------- ------------
1,618,466 1,621,372
Construction work-in-progress 55,255 55,670
---------- ------------
1,673,721 1,677,042
---------- ------------
Investments in subsidiaries and other property, net 64,108 34,022
---------- ------------
Current Assets:
Cash and cash equivalents 16,107 15,197
Accounts receivable less provision for uncollectible accounts:
$4,275 -1999 and $3,461 -1998 106,634 114,380
Materials, supplies and fuel, at average cost 27,888 25,776
Other 5,461 2,692
---------- ------------
156,090 158,045
---------- ------------
Deferred Charges:
Regulatory tax asset 65,617 65,619
Other regulatory assets 63,884 61,675
Other 15,770 15,417
---------- ------------
145,271 142,711
---------- ------------
$2,039,190 $2,011,820
========== ============
CAPITALIZATION AND LIABILITIES
Capitalization:
Common shareholder's equity $ 671,473 $ 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 606,339 606,450
---------- ------------
1,399,427 1,389,432
---------- ------------
Current Liabilities:
Short-term borrowings 111,300 105,000
Current maturities of long-term debt and preferred stock 30,477 30,473
Accounts payable 62,689 66,032
Accrued interest 12,873 7,535
Dividends declared 20,365 20,365
Accrued salaries and benefits 9,672 12,131
Other current liabilities 41,678 27,759
---------- ------------
289,054 269,295
---------- ------------
Deferred Credits:
Accumulated deferred federal income taxes 163,608 161,697
Accumulated deferred investment tax credit 37,452 37,944
Regulatory tax liability 38,501 38,939
Accrued Retirement Benefits 44,072 42,560
Customer advances for construction 35,552 34,961
Other 31,524 36,992
---------- ------------
350,709 353,093
---------- ------------
$2,039,190 $2,011,820
========== ============
The accompanying notes are an integral part of the financial statements.
4
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
Three Months Ended
March 31,
------------------------------
1999 1998
------------ ---------
(Unaudited)
OPERATING REVENUES:
Electric $144,303 $142,139
Gas 38,027 31,366
Water 10,281 9,217
------------ ---------
192,611 182,722
------------ ---------
OPERATING EXPENSES:
Operation:
Purchased power 40,668 38,375
Fuel for power generation 26,470 23,880
Gas purchased for resale 24,717 19,331
Other 23,782 28,828
Maintenance 5,496 4,696
Depreciation and amortization 19,094 16,921
Taxes:
Income taxes 11,812 12,660
Other than income 4,799 4,893
------------ ---------
156,838 149,584
------------ ---------
OPERATING INCOME 35,773 33,138
------------ ---------
Other Income:
Allowance for other funds used during construction - 971
Other income - net 7 122
------------ ---------
7 1,093
------------ ---------
Total Income Before Interest Changes 35,780 34,231
------------ ---------
INTEREST CHARGES:
Long-term debt 9,861 9,768
Other 2,603 1,908
Alllowance for borrowed funds used during construction
and capitalized interest (198) (1,682)
------------ ---------
12,266 9,994
------------ ---------
INCOME BEFORE OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES 23,514 24,237
Preferred dividend requirements of Company-obligated
mandatorily redeemable preferred securities (1,043) (1,043)
------------ -----------
INCOME BEFORE PREFERRED DIVIDENDS 22,471 23,194
Preferred dividend requirements (1,365) (1,365)
------------ -----------
INCOME APPLICABLE TO COMMON STOCK $21,106 $21,829
============ ===========
The accompanying notes are an integral part of the financial statements.
5
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Three Months Ended
March 31,
------------------------
1999 1998
--------- ---------
(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Income before preferred dividends $22,471 $23,194
Non-cash items included in income:
Depreciation and amortization 19,094 16,921
Deferred taxes and deferred investment tax credit 983 (5,333)
AFUDC and capitalized interest (198) (2,653)
Early retirement and severance amortization 1,047 1,054
Other non-cash 760 156
Changes in certain assets and liabilities:
Accounts receivable 7,746 10,330
Materials, supplies and fuel (2,112) (2,517)
Other current assets (2,769) (2,743)
Accounts payable (3,343) (13,421)
Other current liabilities 16,798 20,010
Other - net (8,344) (1,429)
--------- ---------
Net Cash Flows From Operating Activities 52,133 43,569
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to utility plant (18,909) (24,894)
Non-cash charges to utility plant 258 2,724
Net customer refunds and contributions in aid construction 3,684 4,644
--------- ---------
Net cash used for utility plant (14,967) (17,526)
Investments in subsidiaries and other property - net (30,068) (497)
--------- ---------
Net Cash Used in Investing Activities (45,035) (18,023)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term borrowings 6,293 10,637
Reduction of long-term debt (116) (113)
Additional investment by parent company 8,000 -
Dividends paid (20,365) (19,365)
--------- ---------
Net Cash Used In Financing Activities (6,188) (8,841)
--------- ---------
NET INCREASE IN CASH AND CASH EQUIVALENTS 910 16,705
Beginning balance in Cash and Cash Equivalents 15,197 6,920
--------- ---------
Ending Balance in Cash and Cash Equivalents $16,107 $23,625
========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash Paid During Period For:
Interest $7,793 $5,281
Income Taxes $1,716 -
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-month period ended March 31, 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. It is effective for all fiscal quarters of all
fiscal years beginning after June 15, 1999. The Company is still assessing the
impact of SFAS 133 on its financial condition and results of operations.
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.
7
Financial data for business segments is as follows (in thousands).
March-31-1999 Electric Gas Water Consolidated
- ------------------ ------------- -------------- ----------- -------------
Operating Revenues $144,303 $38,027 $10,281 $192,611
============ ============= ========== ============
Operating income $26,685 $6,289 $2,799 $35,773
============ ============= ========== ============
March-31-1998 Electric Gas Water Consolidated
- ------------------ ------------- -------------- ----------- -------------
Operating revenues $142,139 $31,366 $9,217 $182,722
============ ============= ========== ============
Operating income $26,417 $5,162 $1,559 $33,138
============ ============= ========== ============
8
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
---------------------
The components of gross margin are set forth below (dollars in thousands):
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
----------------- ----------------- ------------------- --------------
Operating Revenues:
Electric $144,303 $142,139 $ 2,164 1.5%
Gas 38,027 31,366 6,661 21.2%
Water 10,281 9,217 1,064 11.5%
----------------- ----------------- ------------------- --------------
Total Revenues 192,611 182,722 9,889 5.4%
Energy Costs:
Electric 67,138 62,255 4,883 7.8%
Gas 24,717 19,331 5,386 27.9%
----------------- ----------------- ------------------- --------------
Total Energy Costs 91,855 81,586 10,269 12.6%
----------------- ----------------- ------------------- --------------
Gross Margin $100,756 $101,136 $ (380) -0.4%
================= ================= =================== ==============
Gross Margin by Segment:
Electric $ 77,165 $ 79,884 $(2,719) -3.4%
Gas 13,310 12,035 1,275 10.6%
Water 10,281 9,217 1,064 11.5%
----------------- ----------------- ------------------- --------------
Total $100,756 $101,136 $ (380) -0.4%
================= ================= =================== ==============
The causes for significant changes in specific lines comprising the results
of operations are as follows (dollars in thousands):
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
---------------- ----------------- ------------------- -------------
Electric Operating Reveunes:
Residential $ 47,525 $ 46,526 $ 999 2.1%
Commercial 43,405 41,802 1,603 3.8%
Industrial 45,367 43,992 1,375 3.1%
---------------- ----------------- ------------------- -------------
Retail revenues 136,297 132,320 3,977 3.0%
Other 8,006 9,819 (1,813) -18.5%
---------------- ----------------- ------------------- -------------
Total Revenues $ 144,303 $ 142,139 $ 2,164 1.5%
================ ================= =================== =============
Total retail sales
megawatt-hours (MWH) 2,093,767 2,024,515 69,252 3.4%
---------------- ----------------- ------------------- -------------
Average retail revenue
per MWH $ 65.10 $ 65.36 $ (0.26) -0.4%
Residential revenues increased due to a 2.4% increase in total customers
over the prior period.
Commercial revenues increased primarily due to a 3.3% increase in
customers over the prior period.
Industrial revenues increased due to a 5.8% increase in customers and
higher use per customer. The increase in use per customer was the result of two
large mining customers that increased production over the prior period. The
9
increased revenues were partially offset by other non-volumetric customer
charges that were $.3 million lower than the prior period.
Other revenues were lower in 1999, due primarily to a reclassification to
revenues of $4.3 million from operating expense in order to reflect a refund
resulting from the 1997 earnings sharing decision by the Public Utilities
Commission of Nevada (PUCN). This reduction in revenues was partially offset by
increased wholesale electric revenues ($2.0 million over 1998) and increased
miscellaneous electric revenues of $.5 million over the prior year.
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
--------------- ---------------- -------------- ------------
Gas Operating Revenues:
Residential $ 16,943 $ 16,070 $ 873 5.4%
Commercial 8,838 8,644 194 2.2%
Industrial 3,727 3,848 (121) -3.1%
Miscellaneous 531 335 196 58.5%
--------------- ---------------- -------------- ------------
Total retail revenue 30,039 28,897 1,142 4.0%
Wholesale revenue 7,988 2,469 5,519 223.5%
--------------- ---------------- -------------- ------------
Total Revenues $ 38,027 $ 31,366 $ 6,661 21.2%
=============== ================ ============== ============
Sales (Decatherms):
Retail 5,399,835 5,250,070 149,765 2.9%
Wholesale 3,750,936 1,247,526 2,503,410 200.7%
--------------- ---------------- -------------- ------------
Total 9,150,771 6,497,596 2,653,175 40.8%
--------------- ---------------- -------------- ------------
Average revenues per decatherm
Retail $ 5.56 $ 5.50 $ 0.06 1.1%
Wholesale $ 2.13 $ 1.98 $ 0.15 7.6%
Residential and commercial revenues were higher because of 4.1% and 3.7%
increases in customers, respectively.
Industrial revenues were lower because of warmer weather during 1999
that contributed to lower use per customer.
Wholesale revenues were considerably higher in 1999, due primarily to
the addition of three large wholesale gas contracts.
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
--------------- --------------- ----------------- -----------------
Water Operating Reveunes $10,281 $9,217 $1,064 11.5%
=============== =============== ================= =================
Water revenues were higher due to a price increase effective April 2, 1998
($.6 million) and the combined effect of a 3.3% increase in customers, higher
use per customer as a result of lower precipitation and higher miscellaneous
water revenues ($.5 million).
10
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
----------------- ------------------ ---------------------- ----------------
Purchased Power $ 40,668 $ 38,375 $ 2,293 6.0%
Purchased Power MWH 1,319,795 1,188,202 131,593 11.1%
Average cost per MWH of
Purchased Power $ 30.81 $ 32.30 $ (1.49) -4.6%
Purchased power costs were higher because of purchases associated with
higher wholesale electric sales as discussed previously. Also, the Company
increased purchased power and decreased generation because of the availability
of less expensive hydroelectric power from the Pacific Northwest during 1999.
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
---------------- ----------------- ----------------- -------------
Fuel for Power Generation $ 26,470 $ 23,880 $ 2,590 10.8%
MWHs generated 1,172,367 1,229,753 (57,386) -4.7%
Average cost per MWH of
Generated Power $ 22.58 $ 19.42 $ 3.16 16.3%
Fuel for generation costs were higher because of increased gas unit prices
and the absence of Department of Energy co-funding of fuel costs at the Pinon
Pine project. Both items increased fuel costs over the prior year by
approximately $4.2 million. However, the increase in fuel for generation costs
was partially offset by lower coal prices and reduced generation due to both a
temporary planned plant outage and greater purchased power as discussed
previously.
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
----------------- ---------------- ------------------ ---------------
Gas Purchased for Resale
Retail $ 17,561 $ 16,901 $ 660 3.9%
Wholesale 7,156 2,430 4,726 194.5%
----------------- ---------------- ------------------ ---------------
Total $ 24,717 $ 19,331 $ 5,386 27.9%
================= ================ ================== ===============
Gas Purchased for Resale (decatherms)
Retail 5,403,541 5,248,235 155,306 3.0%
Wholesale 3,750,936 1,247,526 2,503,410 200.7%
----------------- ---------------- ------------------ ---------------
Total 9,154,477 6,495,761 2,658,716 40.9%
================= ================ ================== ===============
Average cost per decatherm
Retail $ 3.25 $ 3.22 $ 0.03 0.9%
Wholesale $ 1.91 $ 1.95 $ (0.04) -2.1%
Consistent with the increase in residential and commercial gas revenues from
customer growth, retail gas purchases were also higher. Also, wholesale gas
purchases were considerably higher than in the prior year due to the increase in
wholesale revenues as previously discussed.
11
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
-------------- -------------- --------------- ---------------
Allowance for other funds used
during construction $ - $ 971 $ (971) -100.0%
Allowance for borrowed funds used
during construction 198 1,682 (1,484) -88.2%
-------------- -------------- --------------- ---------------
$ 198 $2,653 $(2,455) -92.5%
============== ============== =============== ===============
Total allowance for funds used during construction (AFUDC) is lower 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.
Three Months
Ended March 31,
---------------
Change from Change from
1999 1998 Prior Year $ Prior Year %
--------------- --------------- ----------------- -----------------
Other operating expense $23,782 $28,828 $(5,046) -17.5%
Maintenance expense 5,496 4,696 800 17.0%
Depreciation and amortization 19,094 16,921 2,173 12.8%
Income taxes 11,812 12,660 (848) -6.7%
Interest charges-other 2,603 1,908 695 36.4%
Other operating expense decreased due to the reclassification of $4.3
million to a contra-revenue account (See the change in electric-other revenues
discussed previously). Also, operating expense was lower because of consulting
work performed during 1998 of approximately $.5 million. Other immaterial items
combined for the balance of the change from the prior period.
Maintenance expense increased over the prior year due to planned maintenance
performed at two of the Company's electric generating facilities during 1999.
Depreciation and amortization expense increased due to the completion of the
Alturas intertie in December 1998 (approximately $.8 million) and Pinon post-
gasification facilities closed to plant in June 1998 (approximately $.5
million). The balance of the increase resulted from other electric, gas and
water additions.
Operating income taxes were lower due to lower pre-tax income and a lower
effective tax rate during the current year.
Interest charges-other were higher because of the Public Utilities
Commission of Nevada's decision to assess partial interest to amounts payable in
the 1997 earnings sharing case. See the Regulatory Matters section for more
information.
FINANCIAL CONDITION, LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------------------
During the first three months of 1999, the Company earned $22.5 million in
income before preferred dividends. It declared $1.4 million in dividends to
holders of its preferred stock and declared $19 million in common stock
dividends to its parent, Sierra Pacific Resources.
12
The overall increase in cash flows during the first three months of 1999 was
less than 1998 due to more cash used for both investing and financing activities
which was partially offset by more cash provided from operating activities. The
increase in cash provided from operating activities was primarily due to a
greater reduction in accounts payable during the prior year. 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. Financing activities utilized less cash because of a contribution from
the Company's parent corporation.
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), 15.0 million (13.3%)
had been spent as of March 31, 1999. Internally-generated funds exceeded all
construction expenditures.
Environmental
- -------------
As part of the generation divestiture process, discussed in the following
Merger section, the Company has completed Phase 1 Environmental Site Assessments
on all its generation assets. These assessments represent conclusions of an
independent environmental auditor as to the potential environmental concerns at
these facilities. Additionally, Phase 2 Environmental Site Assessments,
consisting of extensive soil and groundwater investigations, were conducted at
the Fort Churchill, North Valmy and Tracy Power Stations. These studies, also
conducted by a independent environmental auditor, have been submitted to the
Nevada Division of Environmental Protection (NDEP) for their review. The
results of NDEP's review are expected no latter than May 1999. Based on a
preliminary review of both studies, the Company's management believes that a
material adjustment to the environmental contingency will not be required.
Prior to conducting the Phase 2 Site Assessments the Company entered into
an Environmental Audit Agreement with the NDEP that protects the Company from
all administrative or civil penalties for environmental discoveries as a result
of the investigations. This agreement is assignable to successor owners of the
Company's generation assets provided the new owners agree upon all items and
conditions.
Merger
- ------
As reported in Sierra Pacific Resources' (SPR's), Report on Form 8-K dated
April 29, 1998, SPR and Nevada Power Company (Nevada Power) entered into an
Agreement and Plan of Merger, dated as of April 29, 1998, providing for a merger
of equals transaction between the companies.
Both SPR and Nevada Power held special stockholder meetings in October 1998
during which stockholders of both companies voted to approve the proposed
merger. On December 31, 1998, the Public Utilities Commission of Nevada (PUCN)
approved the proposed merger subject to conditions, that included among other
items, filings with the PUCN of a divestiture plan for the companies' generating
plants and a rate case to establish revenue requirements and unbundle costs by
service. The approval also required the companies to file a generation
aggregation tariff and a proposal for an independent scheduling administrator
with the Federal Energy Regulatory Commission (FERC). On April 12, 1999, the
PUCN issued an order to appear and show cause to determine if the companies are
in compliance with the merger order conditions. The show cause hearing is
scheduled for May 10, 1999.
On April 1, 1999, consistent with the merger order, the Company filed the
revenue requirements and unbundling study portions of the compliance filing with
the PUCN (see Nevada Matters--Compliance Plan).
Also, as required by the PUCN merger order, both companies submitted a joint
divestiture plan to the PUCN on April 15, 1999, describing plans to sell the
companies' generating units. Upon selling the generating units, the 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, and any goodwill related to the
generation plants. If the companies demonstrate 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 companies may include
13
in the general rate case a request to recover any remaining goodwill." The
Company expects that the generation sales will be completed by late-2000.
On March 31, 1999, as directed by the merger order, the Company filed with
the FERC generation aggregation tariffs that contain rates, terms and conditions
under which the new owners of the Company's generation would operate after
divestiture. The tariff permits market-based rates after the offering of
capacity under a cost-based "recourse" approach.
The proposed merger is also subject to regulatory approvals (or waivers) by
the SEC, Department of Justice and the FERC. The Department of Justice
terminated the Hart-Scott-Rodino waiting period with respect to the proposed
merger on April 16, 1999. The companies received the FERC approval on April 14,
1999. The companies have not yet received approval from the SEC. The companies
expect all approvals by mid-1999.
Through March 31, 1999, the Company had incurred a total of $10.8 million in
capitalized costs since the merger work began. See the SPR Form 8-K dated July
7, 1998, for additional details relating to the merger application filing.
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. These refund obligations have been recognized.
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."
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. SB438 contains several changes to AB366
including changing the start date
14
of competition to March 1, 2000 for all customers. The bill allows the utility
to retain its name and logo for affiliated businesses. The bill does not allow
the PUCN to assign to a provider of last resort customers who do not choose a
supplier of electricity. SB438 now moves to the Nevada Assembly. The Company
cannot predict whether this, or other measures related to industry
restructuring, will be adopted into law. See the Company's Annual Report Form
10K 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
- ---------------
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.
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.
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. This version of the proposed rule may be changed again before being
adopted as final based on comments from the parties and additional hearings.
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.
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.
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 26th. A new procedural final order was issued regarding
those matters.
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.
15
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.
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.
16
FERC Matters
------------
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).
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.
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.
Alturas Intertie
On February 26, 1999, the FERC set for hearing the Alturas Intertie
operating and scheduling agreement filed on December 22, 1998. The FERC also
initiated a Section 206 investigation into the previously approved
interconnection and operations and maintenance agreements. In the same order,
the FERC established settlement judge procedures to attempt to resolve issues
related to these agreements and avoid formal hearings. The parties have held
several meetings in an attempt to negotiate an acceptable settlement. The
matter will move to hearing, currently scheduled for the fall of 1999, if an
agreement cannot be reached.
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.
17
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.
As of this date, the Company has successfully completed testing remediation
with respect to 100% of its mainframe business systems and has a few peripheral
support systems remaining that have a target completion date of July 1999. The
Company is on schedule to meet that date.
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 March 31, 1999,
over 70% of the Company's mission critical embedded systems are Y2K ready and
the Company expects that all systems will be Y2K ready by June 30, 1999.
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 all
Y2K testing and remediation complete by June 30, 1999. The Company is trying to
minimize outages to its customers by scheduling some Y2K testing and remediation
around planned plant maintenance that will occur during non-peak generating
periods in the spring of 1999. The Company's embedded systems remediation plans
call for all Y2K corrective procedures to be complete by June 1999.
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 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. Specific contingency plans
are in final draft form and the Company expects all plans to be complete by the
end of the 2nd quarter of 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.
18
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 feels that its most likely worst case scenario is that one 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 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 more than 70% of mission critical components tested through March 31,
1999, findings in the field continue to 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 the reduced costs
below.
The Company currently estimates that its total incremental expenditures for
the Y2K effort, since it began identification of Y2K cost, will be approximately
$6.3 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 $2.7 million has been incurred through March 31,
1999.
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.
19
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 three month period ended
March 31, 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
20
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: May 14, 1999 By /s/ Mark A. Ruelle
-------------------------- --------------------------
Mark A. Ruelle
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer)
Date: May 14, 1999 By /s/ Mary O. Simmons
-------------------------- --------------------------
Mary O. Simmons
Controller
(Principal Accounting Officer)
21