Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Enova Corporation and SDG&E
Background
On January 1, 1996, Enova Corporation (referred to herein as Enova, which
includes the parent and its wholly owned subsidiaries) became the parent of San
Diego Gas & Electric. SDG&E's outstanding common stock was converted on a share-
for-share basis into Enova Corporation common stock. SDG&E's debt securities,
preferred stock and preference stock were unaffected and remain with SDG&E.
On October 14, 1996, Enova and Pacific Enterprises, Inc., parent company of
Southern California Gas Company, announced that they have agreed to combine the
two companies. As a result of the combination, which was unanimously approved by
the boards of directors of both companies, (i) each outstanding share of common
stock of Enova will be converted into one share of common stock of the new
company, (ii) each outstanding share of common stock of Pacific Enterprises will
be converted into 1.5038 shares of the new company's common stock and (iii) the
preferred stock and preference stock of SDG&E, Pacific Enterprises and Southern
California Gas will remain outstanding. On March 11, 1997, the shareholders of
Enova and Pacific Enterprises approved the combination. Consummation of the
combination is conditional upon the approvals of the California Public Utilities
Commission and various other regulatory bodies. Completion of the combination is
expected by the end of 1997. Additional information regarding the proposed
business combination is described in Note 1 of the notes to consolidated
financial statements.
SDG&E is an operating public utility engaged in the electric and gas
businesses. It generates and purchases electric energy and distributes it to 1.2
million customers in San Diego County and an adjacent portion of Orange County,
California. It also purchases and distributes natural gas to 711,000 customers
in San Diego County and also transports electricity and gas for others. Enova
has six other subsidiaries (referred to herein as non-utility subsidiaries).
Enova Financial invests in limited partnerships representing approximately 1,100
affordable-housing properties located throughout the United States. Califia
leases computer equipment. The investments in Enova Financial and Califia are
expected to provide income-tax benefits over the next several years. Enova
Energy is an energy management and consulting firm offering services to
utilities and large consumers. Enova Technologies is in the business of
developing new technologies generally related to utilities and energy. On
January 14, 1997, Enova Energy and Enova Technologies formed a joint venture
with certain subsidiaries of Pacific Enterprises to provide integrated energy
and energy-related products and services. The merger agreement with Pacific
Enterprises provides that if the business combination is not consummated, either
party can terminate the joint venture. Enova International is involved in
natural gas and power projects outside the United States. Pacific Diversified
Capital is the parent company of Phase One Development, which is engaged in
real-estate development. Additional information regarding Enova's subsidiaries
is described in Notes 2 and 3 of the notes to consolidated financial statements.
Results of Operations
Operating Revenues Electric revenues increased 6 percent in 1996, primarily
due to the accelerated recovery of San Onofre Nuclear Generating Station Units
2 and 3. Additional information about the SONGS recovery and depreciation is
discussed below and in Note 2 of the notes to consolidated financial statements.
Gas revenues increased 12 percent in 1996, reflecting higher purchased-gas
prices. Gas revenues decreased 10 percent in 1995, reflecting lower purchased-
gas prices, weather-related lower sales volume and an increase in customers'
purchases of gas directly from other suppliers (for whom SDG&E provides
transportation).
Operating Expenses Electric fuel expense increased 34 percent in 1996,
primarily due to increased nuclear and natural gas-fired generation, as well as
increases in natural gas prices. Electric fuel expense decreased 30 percent in
1995, primarily due to lower prices for natural gas and the shifting of energy
supply sources from generation to purchased power as a result of two nuclear
refuelings during the year.
Purchased-power expenses decreased 9 percent in 1996, reflecting the
availability of lower-cost nuclear generation and decreases in purchased-power
capacity charges due to a surplus of power from hydro-powered plants in the
Northwest.
Gas purchased for resale increased 34 percent in 1996, primarily due to
higher natural gas prices. Gas purchased for resale decreased 23 percent in
1995, primarily due to lower prices for natural gas, and lower sales volumes due
to warmer weather and an increase in customers' purchases of gas directly from
other suppliers.
The changes in maintenance expenses reflect higher power plant emissions
costs and the nuclear refuelings in 1995.
The increase in depreciation and decommissioning expense in 1996 is
primarily due to the accelerated recovery of SONGS Units 2 and 3.
The increase in general and administrative expenses in 1996 includes start-
up costs for Enova Energy, Enova Technologies and Enova International, expenses
related to the proposed merger with Pacific Enterprises, and higher costs for
customer service.
Earnings 1996 earnings per common share were $1.98 compared to $1.94 in 1995
and $1.17 in 1994. 1994 earnings per common share from continuing operations
were $1.71. The increase in earnings in 1996 is primarily due to demand-side
management rewards, partially offset by SDG&E's lower authorized return on
equity. The increase in earnings from continuing operations in 1995 was due to
numerous offsetting factors, including the 1994 writedowns (described in Note 2
of the notes to consolidated financial statements), SDG&E's increased authorized
return on equity, and changes in incentive rewards for Performance-Based
Ratemaking and demand-side management programs.
Earnings per share for the quarter ended December 31, 1996, were $0.47,
compared to $0.50 for the same period in 1995. The decrease in earnings for the
quarter was due to numerous offsetting factors, including SDG&E's lower
authorized return on equity, changes in incentive rewards for Performance-Based
Ratemaking and demand-side management
programs, and 1995 earnings associated with discontinued operations.
Califia and Enova Financial's contributions to earnings for the year were
$0.19 in 1996, $0.17 in 1995 and $0.15 in 1994. The impact of the remaining
subsidiaries on earnings was not material.
Liquidity and Capital Resources
SDG&E's operations continue to be a major source of liquidity. In addition,
financing needs are met primarily through issuances of short-term and long-term
debt and of common and preferred stock. These capital resources are expected to
remain available. Cash requirements include plant construction and other capital
expenditures, non-utility subsidiaries' affordable-housing, leasing and other
investments, and repayments and retirements of long-term debt. In addition to
changes described elsewhere, major changes in cash flows are described below.
Cash Flows from Operating Activities The major changes in cash flows from
operations among the three years result from changes in regulatory balancing
accounts, income taxes, and accounts payable and other current liabilities. The
changes in cash flows related to
regulatory balancing accounts were primarily due to changes in prices for
natural gas. The changes in cash flows related to income taxes were primarily
due to higher 1996 income tax payments in connection with settlements with the
Internal Revenue Service on the timing of certain deductions in prior years. The
changes in accounts payable and other current liabilities were primarily due to
increased natural gas purchases in 1996 and greater demand-side management
activity in 1995.
Quarterly cash dividends of $0.39 per share were declared for the year
ended December 31, 1996. The dividend payout ratios for the years ended December
31, 1996, 1995, 1994, 1993 and 1992 were 79 percent, 80 percent, 130 percent, 82
percent and 81 percent, respectively. The increase in the payout ratio for the
year ended December 31, 1994, was due to the writedowns recorded during 1994.
Additional information regarding the writedowns is provided in Notes 2 and 3 of
the notes to consolidated financial statements. The payment of future dividends
is within the discretion of the Enova Board of Directors and is dependent upon
future business conditions, earnings and other factors. Net cash flows provided
by operating activities currently are sufficient to maintain the payment of
dividends at the present level.
Cash Flows from Financing Activities Enova did not issue additional stock
or long-term debt in 1996 except for refinancings and does not plan any
issuances in 1997 other than
for refinancings.
In May 1996, the CPUC approved SDG&E's request to issue up to $300 million
of long-term debt to refinance previously issued long-term debt. The decision
also grants a two-year extension of a prior CPUC authorization to issue $138
million of long-term debt and $100 million of preferred stock.
During 1996, SDG&E issued $130 million of Pollution Control Bonds and $99
million of Industrial Development Bonds. The funds obtained from these issues
were used to retire previously issued Pollution Control Bonds and Industrial
Development Bonds of $129 million and $126 million, respectively. Enova
Financial and Califia repaid $29 million of long-term debt in 1996 during the
ordinary course of business.
SDG&E's capital structure is one factor that has enabled it to obtain long-
term financing at attractive rates. The following table shows the percentages of
capital represented by the various components. The capital structures are net of
the construction funds held by a trustee in 1992 and 1993.
1992 1993 1994 1995 1996 Goal
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Common equity 47 % 47 % 48 % 49 % 50 % 46-49 %
Preferred stock 5 4 4 4 4 3-5
Debt and leases 48 49 48 47 46 46-49
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Total 100 % 100 % 100 % 100 % 100 % 100 %
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The CPUC regulates SDG&E's capital structure, limiting the dividends it may
pay Enova. At December 31, 1996, $67 million of common equity was available for
future dividends. This restriction is not expected to affect Enova's ability to
meet its cash obligations.
During 1996, Standard & Poor's Ratings Group upgraded SDG&E's long-term-
bond rating from an A+/negative outlook to an A+/positive outlook following the
passage of California's electric-restructuring law and the announcement of
Enova's proposed business combination with Pacific Enterprises. Moody's
Investors Service affirmed SDG&E's long-term-bond rating of A1/stable outlook.
The state of California has authorized the issuance of rate-reduction bonds
to finance a portion of transition costs that residential and commercial
customers will pay from 1998 to 2001. Principal and interest on the bonds will
be paid through a charge on customers' bills. SDG&E is expected to receive
approximately $500 million from the proceeds. The bonds are expected to be
issued by the California Infrastructure and Economic Development Bank in late
1997. Additional information on the bonds is provided below under "Industry
Restructuring."
In January 1996, SDG&E redeemed its $7.20 series preference stock. The
entire $15 million issue was called for mandatory redemption at $101 per share.
Cash Flows from Investing Activities Cash used in investing activities in
1996 included SDG&E's construction expenditures and payments to its nuclear
decommissioning trust. Construction expenditures, excluding nuclear fuel and the
allowance for equity funds used during construction, were $209 million in 1996
and are estimated to be $240 million in 1997. SDG&E continuously reviews its
construction, investment and financing programs and revises them in response to
changes in competition, customer growth, inflation, customer rates, the cost of
capital, and environmental and regulatory requirements. Among other things, the
level of expenditures in the next few years will depend heavily on the impacts
of industry restructuring, and on the timing of expenditures to comply with air-
emission reduction and other environmental requirements.
Payments to the nuclear decommissioning trust are expected to continue
until SONGS is decommissioned, which is not expected to occur before 2013.
Although Unit 1 was permanently shut down in 1992, it is expected to be
decommissioned concurrently with Units 2 and 3.
Enova's level of non-utility expenditures in the next few years will depend
primarily on the activities of its subsidiaries, including the joint venture
with Pacific Enterprises. The Mexican Energy Regulatory Commission has awarded
Enova International and its partners, Pacific Enterprises International and
Proxima S.A. de C.V., the first natural gas privatization license in Mexico,
allowing the partnership to build and operate a natural gas distribution system
in Mexicali, Baja California. The partnership was granted a 30-year license to
supply natural gas to the region, with exclusive rights for the first 12 years.
The Mexican company formed by the three partners, Distribuidora de Gas Natural
de Mexicali, will invest up to $25 million during the first five years of the
license period. Natural gas service to major commercial and industrial users is
expected to begin in the third quarter of 1997, and be extended to more than
25,000 residential customers by the fifth year. Separately, in January 1997, the
partnership submitted a bid to the Mexican Energy Regulatory Commission to build
and operate a natural gas distribution system in Chihuahua, Mexico. The
commission is expected to announce the winning bidder by April 1, 1997. In
addition, Enova International is part of two consortia preparing bids to build
and operate a power plant and natural gas pipeline in Rosarito, Baja California.
Derivatives The policy of Enova is to use derivative financial instruments
to reduce exposure to fluctuations in interest rates, foreign currency exchange
rates and natural gas prices. These financial instruments are with major
investment firms and expose Enova to market and credit risks. At times, these
risks may be concentrated with certain counterparties, although counterparty
non-performance is not anticipated. Enova does not use derivatives for
speculative purposes.
SDG&E periodically enters into interest-rate swap and cap agreements to
moderate its exposure to interest-rate changes and to lower its overall cost of
borrowing. These swap and cap agreements generally remain off the balance sheet
as they involve the exchange of fixed- and variable-rate interest payments
without the exchange of the underlying principal amounts. The related gains or
losses are reflected in the income statement as part of interest expense. SDG&E
would be exposed to interest-rate fluctuations on the underlying debt should
other parties to the agreement not perform. Such non-performance is not
anticipated. At December 31, 1996, SDG&E had an agreement for a floating-to-
fixed rate swap associated with $45 million of variable-rate bonds maturing in
2002.
SDG&E's pension fund periodically uses foreign-currency forward contracts
to reduce its exposure to exchange-rate fluctuations associated with certain
investments in foreign equity securities. These contracts generally have
maturities ranging from three to six months. At December 31, 1996, there were no
forward contracts.
In October 1996, the Enova Energy and SDG&E boards of directors approved
the companies' use of energy derivatives in price-risk management activities for
both hedging and trading purposes within certain limitations imposed by company
policies. The Enova Corporation board has approved the execution of guarantees
by Enova in support of these activities. In November 1996, SDG&E commenced
price-risk management activities, on a limited basis, in the area of hedging
price volatility of natural gas purchases.
Additional information on derivative financial instruments is provided in
Note 8 of the notes to consolidated financial statements.
Electric Industry Restructuring
Background In September 1996, the state of California enacted a law
restructuring California's electric utility industry (AB 1890). The legislation
adopts the December 1995 CPUC policy decision restructuring the industry to
stimulate competition and reduce rates. The new law supersedes the CPUC policy
decision when in conflict.
Beginning in January 1998, customers will be able to buy their electricity
through a Power Exchange. The Power Exchange will obtain power from Qualifying
Facilities, nuclear units, "must-run" facilities (those needed to provide
reactive power, voltage support and transmission stability) and, lastly, from
the lowest-bidding suppliers. The Power Exchange will serve as a wholesale power
pool, allowing all energy producers to participate competitively. An Independent
System Operator (ISO) will schedule power transactions and access to the
transmission system. Consumers also may choose either to continue to purchase
from their local utility under regulated tariffs or to enter into private
contracts with generators, brokers or others. The local utility will continue to
provide distribution services regardless of which source the consumer chooses.
These customer choices will, in effect, open up the service territories of all
California utilities. This will allow Enova to pursue customers outside of
SDG&E's traditional service territory to provide competitive generation and
other energy-related services. This will also allow energy producers, brokers
and others to enter SDG&E's service territory to compete for generation
customers.
In addition, both the CPUC decision and the California legislation provide
that, within certain limits, utilities will be allowed to recover their stranded
costs incurred for certain above-market CPUC-approved facilities, contracts and
obligations through the establishment of a nonbypassable competition transition
charge (CTC). The CPUC's vision is that traditional cost-of-service regulation
will move toward performance-based regulation.
Transition Costs Utilities will be allowed a reasonable opportunity to
recover their stranded costs through December 31, 2001. Stranded costs such as
reasonable employee-related costs directly caused by restructuring and
purchased-power contracts (including those with qualifying facilities) may be
recovered beyond the 1998-2001 time period. Nuclear decommissioning costs are
nonbypassable until fully recovered, although not included as part of transition
costs. These decommissioning costs are expected to be recovered through 2013,
the estimated last year of service for SONGS, but recovery may be accelerated to
the extent possible.
SDG&E's transition cost application, filed in October 1996, identifies $2
billion of stranded costs, including generation, purchased power and qualifying
facilities' contracts, and regulatory assets. These identified transition costs
are subject to CPUC audit and approval. The amounts include sunk costs, as well
as ongoing costs the CPUC finds reasonable and necessary to maintain generation
facilities through December 31, 2001.
For purposes of transition cost recovery, overcollections of $98 million
recorded in the Energy Cost Adjustment Clause and Electric Revenue Adjustment
Mechanism balancing accounts as of December 31, 1996, will be applied to
recovery of transition costs once those costs are approved by the CPUC. Outside
of those exceptions discussed above, stranded costs not recovered by December
31, 2001, will not be collected from customers. Such costs, if any, would be
written off as a charge against earnings. AB 1890 clarifies that all existing
and future consumers must pay CTC, except for a segment of self-generators and
irrigation districts. SDG&E has very few, if any, of these types of customers
and does not anticipate a material impact from the exemption.
Rate-Reduction Bonds The California legislation provides for a 10-percent
reduction of residential and small commercial customers' rates beginning in
January 1998. The utilities intend to finance the rate reduction with the
proceeds of rate-reduction bonds issued by an agency of the state of California.
SDG&E estimates that it will need $500 million of bond proceeds to finance a
decrease in rate base sufficient to result in the desired rate reduction. These
bonds will be repaid over 10 years by SDG&E's residential and small commercial
customers via a charge on their electric bills. SDG&E and the two other major
investor-owned utilities in California are in discussions with the Securities
and Exchange Commission concerning the accounting for the receipt. For financial
reporting purposes, there will be no gain or loss from the issuance of the bonds
or the receipt of the proceeds. SDG&E has not yet determined the details of how
the proceeds will be used and, therefore, is unable to project the impact on
liquidity or on results of operations from utilization of the proceeds.
Rates The California legislation includes a rate freeze for all customers.
Until the earlier of March 31, 2002, or when transition cost recovery is
complete, SDG&E's system average rate will be frozen at June 10, 1996 levels
(9.64 cents per kwh), except for the impact of natural gas price changes and the
10-percent rate reduction. If gas prices change significantly, SDG&E is
permitted to seek CPUC authority to increase or decrease rates, but rates cannot
be increased above 9.985 cents per kwh.
Late-1996 natural gas prices were more than double early-1996 prices due to
weather-related factors, storage levels, etc., resulting in electric rate
increases in January and February 1997. The rate changes have increased SDG&E's
system average rate from 9.64 cents per kwh to the 9.985 cents-per-kwh rate cap.
Recovery of the transition costs is limited by the rate cap during the 1997
to 2001 transition period. If expenses during a period exceed revenues
authorized under the rate cap, SDG&E will be unable to recover transition costs
during that period. SDG&E will be able to recover transition costs, including
those deferred from earlier periods, in periods in which its other expenses are
under the cap. Transition costs not recovered during the transition period, if
any, will be written off after December 31, 2001. In addition, recovery of
incentive-program rewards such as Performance-Based Ratemaking and demand-side
management is also limited by reward amounts included in current rates, and the
possibility exists that these rewards may not be recoverable until after 2001,
if at all.
Balancing Accounts SDG&E has proposed the elimination of 18 electric
balancing accounts, including ERAM and ECAC, and the retention of the
catastrophic event and hazardous waste memorandum accounts. The CPUC is
currently evaluating the issue.
Elimination of ERAM and ECAC will result in earnings volatility beginning
with the first quarter of 1997. Although no significant effect is expected for
any full year, quarterly earnings will fluctuate significantly, as is already
the case for many electric utilities. The largest impacts will be reduced first-
quarter earnings and increased third-quarter earnings.
Regulatory Accounting Standards SDG&E accounts for the economic effects of
regulation in accordance with Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation," under which a
regulated entity may record a regulatory asset if it is probable that, through
the ratemaking process, the utility will recover that asset from customers.
Regulatory liabilities represent future reductions in revenues for amounts due
to customers.
The SEC has indicated a concern that the California investor-owned
utilities may not meet the criteria of SFAS No. 71 with respect to their
electric-generation net regulatory assets. While discussions are ongoing with
the SEC, if a decision is ultimately made that would result in the
discontinuation of the application of SFAS No. 71 for electric-generation
operations, the impact of a writeoff of SDG&E's generation-related net
regulatory assets would not be material to SDG&E's financial condition, results
of operations or liquidity.
Performance-Based Ratemaking The CPUC has affirmed its belief that the new
competitive environment should be based on policies that encourage efficient
operation and improved productivity rather than on reasonableness reviews and
disallowances. On an experimental basis, SDG&E is participating in a PBR process
for base rates, gas procurement, and electric generation and dispatch, beginning
in 1993. SDG&E has applied to extend the gas procurement mechanism. The genera-
tion and dispatch mechanism is in the process of being terminated, possibly to
be replaced by a new generation mechanism with diminished scope. In addition,
SDG&E plans to file a proposal for a new distribution PBR mechanism, which has
been delayed pending further CPUC guidance. Discussions are ongoing.
Rates for generation services that the ISO determines will be required to
provide reliable service may remain cost-of-service based. These services may be
provided under a contract with the ISO, which will be terminable when the ISO
determines it no longer requires them. Regardless of whether these services are
provided to the ISO under a traditional cost-of-service or PBR-based contract,
SDG&E expects to recover its costs of production and the cost of having its
generating units available.
Federal Restructuring Activities In April 1996, the Federal Energy
Regulatory Commission issued a final rule that will require all utilities to
offer wholesale "open-access" transmission service on a nondiscriminatory basis
and to share information about available transmission capacity.
In November 1996, the FERC approved a proposal by the three California
investor-owned utilities to create a Power Exchange and Independent System
Operator to run California's electric transmission facilities. The FERC, which
has jurisdiction over the exchange, the ISO and interstate transmission,
accepted the proposal to separate the ISO from the Power Exchange and to charge
access fees to recover transmission costs and congestion fees to encourage
efficient use of the system.
Several bills on electric industry restructuring were filed in 1996 at the
federal level. One bill would make states establish rules to let all residences,
businesses and industries choose their own power suppliers by December 15, 2000,
or force states to give way to the FERC to open the local market to competition
after 2000. Another bill calls for full customer choice by January 1, 1998. This
measure provides that if retail choice is not a reality by that date, the FERC
will set rates until competition takes effect. A third bill, introduced on the
last day of the 1996 Congressional session and, therefore, too late for hearings
or debate, would, if reintroduced and enacted as written, supersede state
regulations and legislations, and prevent utility customers from being charged
for stranded investments of the utilities. The other bills and similar bills
introduced in 1997 would mandate recovery of stranded costs or leave the
recovery to the discretion of each state.
Natural Gas
The ongoing restructuring of the natural gas utility industry has allowed
customers to bypass utilities as suppliers and, to a lesser extent, as
transporters of natural gas. Currently, non-utility electricity producers and
other large customers may use a natural gas utility's facilities to transport
gas purchased from non-utility suppliers. Also, smaller customers may form
groups to buy natural gas from another supplier.
Cost of Capital
In November 1996, the CPUC adopted the agreement between SDG&E and the CPUC's
Office of Ratepayer Advocates setting SDG&E's authorized rate of return, return
on equity and capital structure. SDG&E's 1997 return on equity will remain at
11.60 percent and the overall rate of return will change from 9.37 percent to
9.35 percent. This establishes the basis for SDG&E's new cost of capital
mechanism, the Market Indexed Capital Adjustment Mechanism (MICAM), effective
January 1, 1998, which will automatically reset SDG&E's return annually based on
changes in market interest rates. SDG&E's authorized capital structure remains
49.75 percent common equity, 44.5 percent long-term debt and 5.75 percent
preferred stock.
During the industry-restructuring transition period, MICAM will apply to
distribution rate base and the generation rate base not being recovered in CTC.
After the transition period, MICAM will apply to distribution rate base only.
Transmission will be regulated by the FERC.
Resource Planning
Sources of Fuel and Energy SDG&E's primary sources of fuel and purchased
power include natural gas from Canada and the Southwest, surplus power from
other utilities in the Southwest and the Northwest, and uranium from Canada.
Although short-term natural gas supplies are volatile due to weather and other
conditions, these sources should provide SDG&E with an adequate supply of low-
cost natural gas. SDG&E is currently involved in litigation concerning its long-
term contracts for natural gas with certain Canadian suppliers. SDG&E has long-
term pipeline capacity commitments related to its contracts for Canadian natural
gas supplies. If the supply of Canadian natural gas to SDG&E is not resumed,
SDG&E intends to use the capacity in other ways. SDG&E cannot predict the
outcome of the litigation, but does not expect that an unfavorable outcome would
have a material effect on its financial condition, results of operations or
liquidity.
San Onofre Nuclear Generating Station In January 1996, the CPUC approved
the accelerated recovery of the existing capital costs of Units 2 and 3. The
decision allowed SDG&E to recover its remaining investment in the units at a
lower rate of return over an 8-year period beginning in 1996, rather than over
the life of the units' license, which extends to 2013. The accelerated recovery
began in April 1996. At December 31, 1996, approximately $670 million was
unrecovered. California electric-industry-restructuring legislation requires
that all generation-related stranded assets, which includes Units 2 and 3, be
recovered by 2001. The January decision also includes a performance incentive
plan that encourages continued, efficient operation of the plant. Through Decem-
ber 31, 2003, customers will pay about $0.04 per kilowatt-hour. This pricing
structure replaces the traditional method of recovering the units' operating
expenses and capital improvements. This is intended to make the units more
competitive with other sources.
Cracked and dented tubes were found during the latest refueling of Unit 2.
This delayed the restart of the unit and added to the cost of the refueling. The
problems and the resultant need to plug a small percentage of the unit's tubes
will permanently reduce the unit's output and pose the possibility that the
reactor may be taken out of service prior to 2013.
Environmental Matters
SDG&E's operations are conducted in accordance with federal, state and local
environmental laws and regulations governing hazardous wastes, air and water
quality, land use and solid-waste disposal. SDG&E incurs significant costs to
operate its facilities in compliance with these laws and regulations, and to
clean up the environment as a result of prior operations of SDG&E or of others.
The costs of compliance with environmental laws and regulations are
normally recovered in customer rates. However, restructuring of the California
electric-utility industry (see above) will change the way utility rates are set
and costs are recovered. SDG&E has proposed the retention of the hazardous waste
memorandum account, which is intended to encompass cleanup costs, including
those related to generation activities, as described below. Capital costs
related to environmental regulatory compliance are intended to be included in
transition costs for recovery through 2001. However, depending on the final
outcome of industry restructuring and the impact of competition, the costs of
compliance with future environmental regulations may not be fully recoverable.
Capital expenditures to comply with environmental laws and regulations were
$6 million in 1996, $4 million in 1995 and $5 million in 1994, and are expected
to aggregate $34 million over the next 5 years. These expenditures primarily
include the estimated cost of retrofitting SDG&E's power plants to reduce air
emissions. They do not include potential expenditures to comply with water-
discharge requirements for the Encina, South Bay and SONGS power plants, which
are discussed below.
Hazardous Wastes In 1994, the CPUC approved the Hazardous Waste
Collaborative which allows utilities to recover cleanup costs of hazardous waste
contamination at sites where the utility may have responsibility or liability
under the law to conduct or participate in any required cleanup. In general,
utilities are allowed to recover 90 percent of their cleanup costs and any
related costs of litigation with responsible parties.
SDG&E disposes of its hazardous wastes at facilities owned and operated by
other entities. Operations at these facilities may result in actual or
threatened risks to the environment or public health. Where the owner or
operator of such a facility fails to complete any corrective action required by
regulatory agencies to abate such risks, applicable environmental laws may
impose an obligation to undertake corrective actions on SDG&E and others who
disposed of hazardous wastes at the facility.
During the early 1900s, SDG&E and its predecessors manufactured gas from
coal and oil at its Station A facility and at two other, small facilities in
Escondido and Oceanside. Certain amounts of residual by-products from the gas-
manufacturing process and subsurface hydrocarbon contamination were discovered
on portions of the Station A site during an environmental assessment, which was
completed in 1996. The estimate for cleanup of the on-site contamination is in
the $3 million to $6 million range. SDG&E may be required to assess whether or
not such contamination extends to off-site locations. Not included in this
estimate are costs related to a shallow underground tank-like structure found
under a public street immediately west of Station A. A risk assessment has been
completed for Station A and SDG&E is completing negotiations for an appropriate
site-remediation work plan with the County of San Diego's Department of Health.
The Escondido facility was remediated during 1990 through 1993 at a cost of
$3 million and a site-closure letter from the Department of Health has been
received. However, contaminants similar to those on the Escondido site have been
observed on adjacent property. SDG&E plans to assess the nature of and whether
it has any liability for these adjacent contaminants. Finally, potential
contaminants resulting from the gas-manufacturing process by-products will be
assessed at the Oceanside facility, as well as on adjacent property. Sufficient
information is not currently available to estimate the extent of remediation
necessary or the amount of cleanup costs for the property adjacent to the
Escondido and Oceanside facilities or at the Oceanside facility itself.
Asbestos was used in the construction of SDG&E's Station B power plant,
which closed in 1993. Renovation, reconditioning or demolition of the facility
will require the removal of the asbestos in a manner complying with all
applicable environmental, health and safety laws. Additionally, reuse of the
facility may require the removal or cleanup of PCBs, paints containing heavy
metals, fuel oil or other substances. SDG&E has assessed the extent of any
possible contamination by these or other hazardous materials at the facility.
The estimated cost of this removal effort is estimated to be between $4 million
and $5 million.
Electric and Magnetic Fields (EMF) In recent property-damage litigation,
the California Supreme Court agreed with SDG&E and unanimously affirmed the 1995
California Court of Appeal decision that the CPUC has exclusive jurisdiction
over EMF health and safety issues. The California Supreme Court also stated
that scientific evidence is insufficient to conclude that EMFs pose a health
hazard. Although scientists continue to research the possibility that exposure
to EMFs causes adverse health effects, to date, science has demonstrated no
cause-and-effect relationship between adverse health effects and exposure to the
type of EMFs emitted by utilities' power lines and other electrical facilities.
Some laboratory studies suggest that such exposure creates biological effects,
but those effects have not been shown to be harmful. The studies that have most
concerned the public are certain epidemiological studies, some of which have
reported a weak correlation between childhood leukemia and the proximity of
homes to certain power lines and equipment. Other epidemiological studies found
no correlation between estimated exposure and any disease. Scientists cannot
explain why some studies using estimates of past exposure report correlations
between estimated EMF levels and disease, while others do not.
To respond to public concerns, the CPUC has directed California utilities
to adopt a low-cost EMF-reduction policy that requires reasonable design changes
to achieve noticeable reduction of EMF levels that are anticipated from new
projects. However, consistent with the major scientific reviews of the
available research literature, the CPUC has indicated that no health risk has
been identified.
Air Quality The San Diego Air Pollution Control District (APCD) regulates
air quality in San Diego County in conformance with the California and Federal
Clean Air Acts. California's standards are more restrictive than federal
standards.
During 1996, SDG&E installed equipment on South Bay Unit 1 in order to
comply with the first tier of nitrogen-oxide emission limits that the APCD
imposed on electric generating boilers through its Rule 69. Under this rule,
SDG&E must maintain the total nitrogen-oxide emissions from its entire system
below a prescribed emissions cap which decreases periodically through 2005. The
estimated capital costs for compliance with the rule are $60 million. The
California Air Resources Board has expressed concern that Rule 69 does not meet
the requirements of the California Clean Air Act and may impose more restrictive
emissions limitations, causing SDG&E's Rule 69 compliance costs to increase.
Under a South Coast Air Quality Management District program called RECLAIM,
SDG&E is required to reduce its nitrogen-oxide emission levels of the natural
gas compressor engines at its Moreno facility by 10 percent a year through 2003.
This will be accomplished through the installation of new emission-monitoring
equipment, operational changes to take advantage of low-emission engines and
engine retrofits. The cost of complying with RECLAIM may be as much as $3
million.
Water Quality Wastewater discharge permits issued by the Regional Water
Quality Control Board (RWQCB) for SDG&E's Encina and South Bay power plants are
required to enable SDG&E to discharge its cooling water and certain other
wastewaters into the Pacific Ocean and into San Diego Bay. The continued cooling
and wastewater discharges and, therefore, the necessary permits are
prerequisites to the continued operation of the power plants as they are
currently configured. Increasingly stringent cooling-water and waste-water
discharge limitations may be imposed in the future and SDG&E may be required to
build additional facilities or modify existing facilities to comply with these
requirements. Such facilities could include waste-water treatment facilities,
cooling towers or offshore-discharge pipelines. However, any required
construction could involve substantial expenditures, and certain plants or units
may be unavailable for electric generation during construction.
In 1981, SDG&E submitted a demonstration study in support of its request
for two exceptions to certain thermal discharge requirements imposed by the
California Thermal Plan for the Encina power plant. In November 1994, the
RWQCB issued a new permit, subject to the results of certain additional
thermal studies to be used in considering SDG&E's exception requests. The
results of these additional studies will be completed in 1997. If SDG&E's
exception requests are denied, SDG&E could be required to construct
off-shore discharge facilities at a cost of $75 million to
$100 million or to perform mitigation.
During 1997, in conjunction with its permit requirements to treat
wastewater at its Encina and South Bay power plants, SDG&E will be evaluating
whether any remediation activities may be required at the power plants.
In addition, SDG&E will be determining whether remediation is required at
its Silvergate plant, which was shut down in 1984. Sufficient information
is not currently available to estimate the costs of any necessary remediation.
The California Coastal Commission required a study of the offshore impact
on the marine environment from the cooling-water discharge by SONGS Units 2 and
3. The study concluded that some environmental damage is caused by the
discharge. To mitigate the damage, the California Coastal Commission ordered
Southern California Edison, SDG&E and the cities of Anaheim and Riverside to
improve the plant's fish-protection system, build a 300-acre artificial reef to
help restore kelp beds and restore 150 acres of coastal wetlands. SDG&E may be
required to incur capital costs of up to $30 million to comply with this order.
The new pricing structure contained in the CPUC's decision regarding accelerated
recovery of SONGS Units 2 and 3 (see "San Onofre Nuclear Generating Station"
above) accommodates these added mitigation costs. In addition, SDG&E and Edison
have asked the California Coastal Commission to reconsider and modify this
mitigation plan to reduce the size of the artificial reef and shorten the
monitoring period based on new studies that show that the environmental damage
is much less than anticipated. Discussions are ongoing.
Wood-Pole Preservatives Mateel Environmental Justice Foundation agreed to
the dismissal, without prejudice, of its complaint against Pacific Bell, Pacific
Gas & Electric and two wood-pole manufacturers in April 1996. The complaint
alleged that utility-pole owners and manufacturers failed to comply with
Proposition 65 requirements to warn the public that the poles are treated with
hazardous chemicals known to the state to cause cancer or reproductive harm.
SDG&E was not a party to the litigation, but had received a copy of the notice
served by Mateel stating its intent to bring suit against responsible parties
using such poles and chemicals.
Information Regarding Forward-Looking Statements
This Annual Report to Shareholders includes forward-looking statements within
the definition of Section 27A of the Securities Act of 1933 and Section 21E of
the Securities Exchange Act of 1934. When used in this "Management's Discussion
and Analysis of Financial Condition and Results of Operations," the words
"estimates," "expects," "anticipates," "plans," and "intends," variations of
such words, and similar expressions are intended to identify forward-looking
statements that involve risks and uncertainties.
Although the Registrants believe that their expectations are based on
reasonable assumptions, they can give no assurance that those expectations will
be realized. Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include political
developments affecting state and federal regulatory agencies, the pace of
electric industry deregulation in California and in the United States, the
existence of or ability to create a market for rate-reduction bonds, the ability
to effect a coordinated and orderly implementation of both state legislation and
the CPUC's restructuring regulations, the consummation and timing of the
combination of Enova and Pacific Enterprises, international political
developments, environmental regulations, and the timing and extent of changes in
interest rates and prices for natural gas and electricity.