UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
March 31, 2008
Commission file number
1-3779
SAN DIEGO GAS & ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
California
95-1184800
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
8326 Century Park Court, San Diego, California 92123
(Address of principal executive offices) (Zip Code)
(619) 696-2000
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the 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 by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
[ ]
Accelerated filer
[ ]
Non-accelerated filer
[ X ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
No
X
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common stock outstanding:
Wholly owned by Enova Corporation
1
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may," "could," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional and national economic, competitive, political, legislative and regulatory conditions and developments; actions by the California Public Utilities Commission, the California State Legislature, the California Department of Water Resources, the Federal Energy Regulatory Commission and other regulatory bodies in the United States; capital markets conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; the availability of electric power, natural gas and liquefied natural gas; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory, environmental and legal decisions and requirements; the status of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; the resolution of litigation; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this report and other reports filed by the company from time to time with the Securities and Exchange Commission.
See Notes to Condensed Consolidated Financial Statements.
3
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
March 31, 2008
December 31, 2007 *
(Dollars in millions)
(unaudited)
ASSETS
Current assets:
Cash and cash equivalents
$
31
$
158
Short-term investments
236
--
Accounts receivable – trade
195
207
Accounts receivable – other
71
49
Due from unconsolidated affiliates
12
22
Income taxes receivable
18
56
Deferred income taxes
65
67
Inventories
61
113
Regulatory assets arising from fixed-price contracts and other derivatives
--
52
Other regulatory assets
14
14
Fixed-price contracts and other derivatives
47
18
Other
21
34
Total current assets
771
790
Other assets:
Due from unconsolidated affiliate
5
5
Deferred taxes recoverable in rates
326
312
Regulatory assets arising from fixed-price contracts and other derivatives
295
309
Regulatory assets arising from pensions and other postretirement benefit obligations
168
162
Other regulatory assets
45
48
Nuclear decommissioning trusts
701
739
Sundry
154
123
Total other assets
1,694
1,698
Property, plant and equipment:
Property, plant and equipment
8,445
8,282
Less accumulated depreciation and amortization
(2,314
)
(2,271
)
Property, plant and equipment, net
6,131
6,011
Total assets
$
8,596
$
8,499
See Notes to Condensed Consolidated Financial Statements.
* As adjusted.
4
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
March 31, 2008
December 31, 2007 *
(Dollars in millions)
(unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt
$
33
$
--
Accounts payable
248
290
Due to unconsolidated affiliates
12
10
Regulatory balancing accounts, net
342
298
Fixed-price contracts and other derivatives
49
52
Customer deposits
52
52
Mandatorily redeemable preferred securities
--
14
Other
237
259
Total current liabilities
973
975
Long-term debt
2,005
1,958
Deferred credits and other liabilities:
Customer advances for construction
31
33
Pension and other postretirement benefit obligations, net of plan assets
195
190
Deferred income taxes
503
506
Deferred investment tax credits
28
29
Regulatory liabilities arising from removal obligations
1,327
1,335
Asset retirement obligations
551
554
Fixed-price contracts and other derivatives
332
329
Deferred credits and other
161
176
Total deferred credits and other liabilities
3,128
3,152
Minority interest
137
135
Commitments and contingencies (Note 6)
Shareholders' equity:
Preferred stock not subject to mandatory redemption
79
79
Common stock (255 million shares authorized; 117 million shares outstanding; no par value)
1,138
1,138
Retained earnings
1,152
1,078
Accumulated other comprehensive income (loss)
(16
)
(16
)
Total shareholders' equity
2,353
2,279
Total liabilities and shareholders' equity
$
8,596
$
8,499
See Notes to Condensed Consolidated Financial Statements.
* As adjusted.
5
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Three months ended
March 31,
(Dollars in millions)
2008
2007
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
$
75
$
63
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization
77
75
Deferred income taxes and investment tax credits
3
(2
)
Noncash rate-reduction bond expense
--
14
Gains on sale of assets
(3
)
(2
)
Net changes in other working capital components
134
122
Changes in other assets
2
3
Changes in other liabilities
(10
)
(7
)
Net cash provided by operating activities
278
266
CASH FLOWS FROM INVESTING ACTIVITES
Expenditures for property, plant and equipment
(235
)
(157
)
Expenditures for investments
(236
)
--
Purchases of nuclear decommissioning trust assets
(134
)
(211
)
Proceeds from sales by nuclear decommissioning trusts
134
213
Decrease in loans to affiliates, net
--
14
Proceeds from sales of assets
1
2
Net cash used in investing activities
(470
)
(139
)
CASH FLOWS FROM FINANCING ACTIVITES
Increase (decrease) in short-term debt, net
33
(72
)
Issuance of long-term debt
47
--
Payments on long-term debt
--
(17
)
Redemptions of preferred stock
(14
)
(3
)
Preferred dividends paid
(1
)
(1
)
Net cash provided by (used in) financing activities
65
(93
)
Increase (decrease) in cash and cash equivalents
(127
)
34
Cash and cash equivalents, January 1
158
9
Cash and cash equivalents, March 31
$
31
$
43
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized
$
15
$
7
Income tax refunds, net
$
1
$
35
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY
Decrease in accounts payable from investments in property, plant and equipment
$
(53
)
$
(32
)
See Notes to Condensed Consolidated Financial Statements.
6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. GENERAL
Principles of Consolidation
This Quarterly Report on Form 10-Q is that of San Diego Gas & Electric Company (SDG&E or the company). SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy, a California-based Fortune 500 holding company. The accompanying financial statements are the Condensed Consolidated Financial Statements of SDG&E and its subsidiary, SDG&E Funding LLC, and Otay Mesa Energy Center LLC (OMEC LLC), a variable interest entity discussed in Note 3.
Sempra Energy also indirectly owns all of the common stock of Southern California Gas Company (SoCalGas). SDG&E and SoCalGas are collectively referred to as the Sempra Utilities.
Basis of Presentation
The Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. In the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.
Information in this Quarterly Report should be read in conjunction with the company’s Annual Report on Form 10-K for the year ended December 31, 2007 (the Annual Report).
The company’s significant accounting policies are described in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The same accounting policies are followed for interim reporting purposes, except for the adoption of new accounting standards as discussed in Note 2.
SDG&E accounts for the economic effects of regulation on utility operations in accordance with Statement of Financial Accounting Standards (SFAS)71, Accounting for the Effects of Certain Types of Regulation.
NOTE 2. NEW ACCOUNTING STANDARDS
Recently issued pronouncements that have had or may have a significant effect on the company's financial statements are described below.
SFAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment of FASB Statement No. 115" (SFAS 159): SFAS 159 allows measurement at fair value of eligible financial assets and liabilities that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item are reported in current earnings at each subsequent reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between the different measurement attributes the company elects for similar types of assets and liabilities. This statement is effective for fiscal years beginning after November 15, 2007. The company did not
7
elect the fair value option at the adoption of SFAS 159 for any of its eligible financial assets or liabilities.
SFAS 161, "Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133" (SFAS 161):SFAS 161 expands the disclosure requirements in Financial Accounting Standards Board (FASB) Statement No. 133,Accounting for Derivative Instruments and Hedging Activities (SFAS 133). SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early application is encouraged. The company is in the process of evaluating the effect of this statement on its financial statement disclosures.
FASB Staff Position (FSP) FIN 39-1, "Amendment of FASB Interpretation No. 39" (FSP FIN 39-1): FSP FIN 39-1 amends certain paragraphs of FASB Interpretation No. 39,Offsetting of Amounts Related to Certain Contracts, to permit a reporting entity to offset fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. FSP FIN 39-1 is effective for fiscal years beginning after November 15, 2007. The company adopted FSP FIN 39-1 effective January 1, 2008. The company applied FSP FIN 39-1 as a change in accounting principle through retrospective application. Each consolidated balance sheet herein reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of setoff exists. Accordingly, December 31, 2007 amounts have been reclassified to conform to this presentation. Additional disclosure is provided in Note 4.
NOTE 3. OTHER FINANCIAL DATA
Variable Interest Entity (VIE)
The company has a 10-year power purchase agreement with OMEC LLC for power generated at the Otay Mesa Energy Center (OMEC), a 573-megawatt (MW) generating facility currently under construction by OMEC LLC, which is expected to be in commercial operation in the second half of 2009. As defined in FIN 46 (revised December 2003),Consolidation of Variable Interest Entities - an interpretation of ARBNo. 51 (FIN 46(R)), OMEC LLC is a VIE, of which the company is the primary beneficiary. Accordingly, the company has consolidated OMEC LLC beginning in the second quarter of 2007. OMEC LLC’s equity of $137 million and $135 million as of March 31, 2008 and December 31, 2007, respectively, is classified as Minority Interest on the Consolidated Balance Sheets.
Available-for-Sale Securities
In March 2008, SDG&E purchased $236 million of industrial development bonds, which are classified as available-for-sale securities and included in Short-Term Investments on the Consolidated Balance Sheet at March 31, 2008. Interest rates on these securities are reset by remarketing agents on a weekly basis at rates intended to permit the bonds to be remarketed at par. The bonds were initially issued as insured, auction-rate securities, the proceeds of which were loaned to SDG&E, and are repaid with payments from SDG&E first mortgage bonds with terms corresponding to those of the industrial development bonds. SDG&E intends to modify the
8
credit support and liquidity requirements of the bonds in conjunction with their subsequent remarketing to investors.
Debt and Credit Facilities
Committed Line of Credit
The company and its affiliate, SoCalGas, have a combined $600 million revolving credit facility expiring in 2010, under which each utility may borrow up to $500 million, subject to a combined borrowing limit for both utilities of $600 million. At March 31, 2008, the company had no outstanding borrowings under this facility. The facility provides support for $33 million of commercial paper outstanding as of March 31, 2008.
Additional information concerning this credit facility is provided in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.
Weighted Average Interest Rate
The company's weighted average interest rate on the total short-term debt outstanding was2.41 percent at March 31, 2008.
Pension and Other Postretirement Benefits
The following table provides the components of benefit costs:
Pension Benefits
Other Postretirement Benefits
Three months ended
Three months ended
March 31,
March 31,
(Dollars in millions)
2008
2007
2008
2007
Service cost
$
6
$
6
$
2
$
2
Interest cost
12
12
2
2
Expected return on assets
(12
)
(12
)
(1
)
(1
)
Amortization of:
Prior service cost
--
1
1
1
Actuarial loss
1
--
--
--
Regulatory adjustment
(6
)
(6
)
(1
)
--
Total net periodic benefit cost
$
1
$
1
$
3
$
4
The company expects to contribute $42 million to its pension plan and $15 million to its other postretirement benefit plans in 2008. For the three months ended March 31, 2008, the company made contributions of a negligible amount and $3 million to the pension plan and other postretirement benefit plans, respectively.
Capitalized Interest
The company recorded $4 million and $2 million of capitalized interest for the three months ended March 31, 2008 and 2007, respectively, including primarily the debt-related portion of allowance for funds used during construction,and, for the three months ended March 31, 2008, capitalized interest related to OMEC LLC.
9
Comprehensive Income
For the three-month periods ended March 31, 2008 and 2007, comprehensive income was equal to net income.
Other Income, Net
Other Income, Net consists of the following:
Three months ended
March 31,
(Dollars in millions)
2008
2007
Allowance for equity funds used during construction
$
6
$
5
Regulatory interest, net
(4
)
(3
)
Sundry, net
1
2
Total
$
3
$
4
NOTE 4. FINANCIAL INSTRUMENTS
The company periodically uses commodity derivative instruments and interest-rate swap agreements to moderate its exposure to commodity price changes and interest-rate changes and to lower its overall cost of borrowing.
Cash Flow Hedges
As of March 31, 2008 and December 31, 2007, the company had established cash flow interest-rate swap hedges for a notional amount of debt totaling $251 million. The swaps expire in 2009. In addition, OMEC LLC has entered into cash flow interest-rate swap hedges for a notional amount of debt ranging from $134 million to $377 million. The swaps expire in 2019.
For the three months ended March 31, 2008 and 2007, pretax gain (loss) arising from the ineffective portion of interest-rate cash flow hedges was a loss of a negligible amount and a gain of $1 million, respectively, and was recorded in Other Income, Net on the Statements of Consolidated Income.
Energy and Natural Gas Contracts
The use of derivative instruments is subject to certain limitations imposed by company policy and regulatory requirements. These instruments enable the company to estimate with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. The company records realized gains or losses on derivative instruments associated with transactions for electric energy and natural gas contracts in Cost of Electric Fuel and Purchased Power and Cost of Natural Gas, respectively,on the Statements of Consolidated Income. On the Consolidated Balance Sheets, the company records corresponding regulatory assets and liabilities related to unrealized gains and losses from these derivative instruments to the extent derivative gains and losses associated with these derivative instruments will be payable or recoverable in future rates.
10
Adoption of FSP FIN 39-1
The company adopted FSP FIN 39-1 effective January 1, 2008, which requires retroactive application. Each Consolidated Balance Sheet herein reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of setoff exists. As of March 31, 2008, the company offset fair value cash collateral payables against net derivative positions of $5 million. As of December 31, 2007, the company offset fair value cash collateral receivables against net derivative positions of $9 million. The fair value of commodity derivative assets and liabilities as of March 31, 2008 and December 31, 2007, determined in accordance with the company's netting policy, is disclosed below. As of March 31, 2008, the fair value of cash collateral was completely offset in the Consolidated Balance Sheet. As of December 31, 2007, the fair value of cash collateral that was not offset in the Consolidated Balance Sheet was $6 million.
Fair Value Hierarchy
The company’s valuation techniques used to measure fair value and the definition of the three levels of the fair value hierarchy, as defined in SFAS 157, Fair Value Measurements (SFAS 157), are discussed in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report.
The following tables set forth by level within the fair value hierarchy the company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008 and December 31, 2007. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Recurring Fair Value Measures
At fair value as of March 31, 2008
(Dollars in millions)
Level 1
Level 2
Level 3
Total
Assets:
Commodity derivatives
$
21
$
28
$
--
$
49
Nuclear decommissioning trusts*
519
175
--
694
Short-term investments
--
236
--
236
Other derivatives
--
--
7
7
Total
$
540
$
439
$
7
$
986
Liabilities:
Other derivatives
$
--
$
38
$
--
$
38
11
Recurring Fair Value Measures
At fair value as of December 31, 2007**
(Dollars in millions)
Level 1
Level 2
Level 3
Total
Assets:
Commodity derivatives
$
9
$
3
$
--
$
12
Nuclear decommissioning trusts*
551
175
--
726
Other derivatives
--
--
7
7
Total
$
560
$
178
$
7
$
745
Liabilities:
Commodity derivatives
$
--
$
8
$
--
$
8
Other derivatives
--
20
--
20
Total
$
--
$
28
$
--
$
28
*
Excludes cash balances.
**
Amounts have been reclassified to reflect the adoption of FASB Staff Position FIN 39-1.
There were no changes in the fair value of net other derivatives classified as level 3 in the fair value hierarchy in the three month periods ended March 31, 2008 and 2007.
NOTE 5. REGULATORY MATTERS
Power Procurement and Resource Planning
Sunrise Powerlink Electric Transmission Line
SDG&E has applied to the California Public Utilities Commission (CPUC) for authorization to construct the Sunrise Powerlink, a 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region that will be able to deliver 1,000 MW. The project, as proposed by the company, is now projected to cost $1.5 billion, which includes an allowance for funds used during construction related to both debt and equity. The increase in total projected cost from previous estimates is primarily due to the delay in the projected in-service date and the increased costs of materials and supplies. The projected cost is subject to change pending the final route, terms, conditions and mitigation requirements stipulated in the CPUC decision.
A proposed decision on the project is expected in July 2008, with a final CPUC decision expected by year-end 2008. Given this timeline, if the project is approved by the CPUC as proposed by the company, the earliest management projects the Sunrise Powerlink would be in commercial operation is in the first half of 2011.
Renewable Energy
Pursuant to Senate Bill 107, enacted in September 2006, the California Public Utilities Code requires certain California electric retail sellers, including the company, to achieve a 20-percent renewable energy portfolio by 2010. The rules governing this requirement, administered by both the CPUC and the California Energy Commission, are generally known as the Renewables Portfolio Standard (RPS) Program.
SDG&E continues to aggressively pursue the acquisition of renewable energy supplies to achieve the RPS program goals. A substantial portion of these supply contracts, however, are contingent upon many factors, including access to electric transmission infrastructure (including SDG&E's proposed Sunrise Powerlink transmission line), timely regulatory approval of contracted renewable
12
energy projects, the renewable energy project developers' ability to obtain project financing, and successful development and implementation of the renewable energy technologies.
Given the current Sunrise Powerlink regulatory proceeding timeline, as discussed above, the Sunrise Powerlink transmission line, if approved, will not be in operation to provide transmission capability to meet the 2010 RPS requirements. Consequently, the company believes it is unlikely that it will be able to meet the 2010 RPS delivered-energy goal. The company's failure to attain the 20-percent goal in 2010, or any subsequent years' goals, could subject it to CPUC-imposed penalties of 5 cents per kilowatt hour of renewable energy under-delivery up to a maximum penalty of $25 million per year. In February 2008, the CPUC issued a decision defining flexible compliance mechanisms that can be used in meeting the RPS goals in 2010 and beyond, including clarifying rules within which insufficient transmission is a permissible reason for failing to satisfy the RPS goals. While the company believes it will be able to comply with the RPS requirements based on its contracting activity and application of the flexible compliance mechanisms, the company is unable to ensure that it will not be penalized or, if penalized, the amount that would be imposed.
General Rate Case (GRC)
In December 2007, the company filed a settlement agreement with the CPUC pertaining to its 2008 General Rate Case (2008 GRC) that would, if approved by the CPUC, provide a 2008 revenue requirement of $1.349 billion and would resolve all 2008 revenue requirement issues. If adopted, the settlement would represent an increase in the annual revenue requirement in 2008 of $138 million, as compared to the 2007 revenue requirement. The company also reached agreement with certain parties in the 2008 GRC, also subject to CPUC approval, regarding post test-year provisions including the duration of the post-test years (2008 GRC period), earnings sharing and the year-to-year increases to the annual authorized revenue during the GRC period. The parties, with the exception of the CPUC's Division of Ratepayer Advocates (DRA), agreed to a GRC term of four years (2008 through 2011), with the DRA separately agreeing to a term of five years (through 2012). All parties agreed to post test-year revenue requirement increases in fixed dollar amounts. All parties also agreed that there would be no earnings sharing between the company and ratepayers should the company achieve earnings above or below the authorized return on equity for any year in the post test-year period.
The company has filed a request with the CPUC to make any decision on the 2008 GRC effective retroactive to January 1, 2008. A final CPUC decision on all 2008 GRC issues, as noted above, is expected in the second quarter of 2008.
As a final CPUC decision in regard to the 2008 GRC has not been issued, the company is reporting first quarter 2008 revenue associated with CPUC-regulated operations consistent with the 2007 revenue requirement as established by the CPUC's 2004 Cost of Service decision.
Utility Ratemaking Incentive Awards
Performance-Based Regulation (PBR) consists of a series of measures of utility performance. Generally, if performance is outside of a band around specified benchmarks, the utility is subject to financial rewards or penalties. The three areas that are eligible for incentive awards or penalties are operational incentives, which measure safety, reliability and customer service; energy efficiency (sometimes referred to as demand-side management, or DSM or EE) awards based on the effectiveness of the energy efficiency programs; and natural gas procurement awards or penalties. The operational PBR incentives, and the associated benchmarks, are determined as a component of a general rate case or cost of service decision. The operational PBR incentives to be in effect for fiscal
13
year 2008 through the end of the 2008 GRC period are under consideration as part of the 2008 GRC. The company has recommended continuing the PBR measures that were in effect through 2007 with slight modifications to the benchmarks. As noted above, the company expects a final CPUC decision on this issue in the second quarter of 2008.
Incentive awards are not included in the company's earnings until CPUC approval of the award is received.
Energy Efficiency
In January 2008, the CPUC issued a decision modifying the measurement and verification process of this incentive mechanism. The company submitted its initial report on its 2006 and 2007 energy efficiency results, as compared to goal, with the CPUC in the first quarter of 2008. A final CPUC decision is anticipated by early 2009.
Natural Gas Procurement
The company’s PBR for natural gas procurement awards or penalties ended on April 1, 2008, the effective date of the combination of the core natural gas supply portfolios, with SoCalGas' gas cost incentive mechanism being applied on the combined portfolio basis, as discussed in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.
NOTE 6. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
At March 31, 2008, the company’s reserves for litigation matters were $42 million, of which $38 million related to settlements reached to resolve certain litigation arising out of the 2000 – 2001 California energy crisis. The uncertainties inherent in complex legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving legal matters. Accordingly, costs ultimately incurred may differ materially from estimated costs and could materially adversely affect the company's business, cash flows, results of operations and financial condition.
Sempra Commodities, Sempra Generation and Sempra LNG, referred to in the following discussion, are business units of Sempra Energy.
Continental Forge Settlement
The litigation that is the subject of the settlements and $38million of reserves is frequently referred to as the Continental Forge litigation, although the settlements also include other cases. The Continental Forge class-action and individual antitrust and unfair competition lawsuits in California and Nevada alleged that Sempra Energy and the Sempra Utilities unlawfully sought to control natural gas and electricity markets and claimed damages in excess of $23 billion after applicable trebling.
The San Diego County Superior Court entered a final order approving the settlement of the Continental Forge class-action litigation as fair and reasonable in July 2006. The California Attorney General and the Department of Water Resources (DWR) have appealed the final order. Oral argument is expected to take place in 2008. The Nevada Clark County District Court entered an order approving the Nevada class-action settlement in September 2006. Both the California and Nevada settlements must be approved for either settlement to take effect, but Sempra Energy
14
is permitted to waive this condition. The settlements are not conditioned upon approval by the CPUC, the DWR, or any other governmental or regulatory agency.
To settle the California and Nevada litigation, in January 2006, Sempra Energy agreed to make cash payments in installments aggregating $377 million, of which $347 million relates to the Continental Forge and California class action price reporting litigation and $30 million relates to the Nevada antitrust litigation. The Los Angeles City Council had not previously voted to approve the City of Los Angeles' participation in the January 2006 California settlement. In March 2007, Sempra Energy and the Sempra Utilities entered into a separate settlement agreement with the City of Los Angeles resolving all of its claims in the Continental Forge litigation in return for the payment of $8.5 million in April 2007. This payment was made in lieu of the $12 million payable in eight annual installments that the City of Los Angeles was to receive as part of the January 2006 California settlement.
Additional consideration for the January 2006 California settlement includes an agreement that Sempra LNG would sell to the Sempra Utilities, subject to CPUC approval, regasified liquefied natural gas (LNG) from its LNG terminal being constructed in Baja California, Mexico, for a period of 18 years at the California border index price minus $0.02 per million British thermal units (MMBtu). Also, Sempra Generation voluntarily would reduce the price that it charges for power and limit the locations at which it would deliver power under its DWR contract. Based on the expected contractual power deliveries, this discount would have potential value aggregating $300 million over the contract's then remaining six-year term.
Under the terms of the January 2006 settlements, $83 million was paid in August 2006 and an additional $83 million was paid in August 2007. Of the remaining amounts, $25.8 million is to be paid on the closing date of the January 2006 settlements, which will take place after the resolution of all appeals, and $24.8 million will be paid on each successive anniversary of the closing date through the seventh anniversary of the closing date, as adjusted for the City of Los Angeles settlement. Under the terms of the City of Los Angeles settlement, $8.5 million was paid in April 2007. The reserves recorded for the California and Nevada settlements by Sempra Energy, including SDG&E, in 2005 fully provide for the present value of both the cash amounts to be paid in the settlements and the price discount to be provided on electricity to be delivered under the DWR contract. A portion of the reserves was discounted at 7 percent, the rate specified for prepayments in the settlement agreement. For payments not addressed in the agreement and for periods from the settlement date through the estimated date of the first payment, 5 percent was used to approximate Sempra Energy's average cost of financing.
Other Natural Gas Cases
In April 2003, Sierra Pacific Resources and its utility subsidiary Nevada Power filed a lawsuit in the U.S. District Court in Nevada against major natural gas suppliers, including Sempra Energy, the Sempra Utilities and Sempra Commodities, seeking recovery of damages alleged to aggregate in excess of $150 million (before trebling). The lawsuit alleges a conspiracy to manipulate and inflate the prices that Nevada Power had to pay for its natural gas by preventing the construction of natural gas pipelines to serve Nevada and other Western states, and reporting artificially inflated prices to trade publications. The U.S. District Court dismissed the case in November 2004, determining that the Federal Energy Regulatory Commission (FERC) had exclusive jurisdiction to resolve the claims. In September 2007, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit Court of Appeals) reversed the dismissal and returned the case to the District Court for further proceedings.
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Apart from the claims settled in connection with the Continental Forge settlement, the remaining 13 state antitrust actions that were coordinated in San Diego Superior Court against Sempra Energy, the Sempra Utilities and Sempra Commodities and other, unrelated energy companies,alleging that energy prices were unlawfully manipulated by the reporting of artificially inflated natural gas prices to trade publications and by entering into wash trades and churning transactions, were settled on January 4, 2008, for $2.5 million.
Pending in the U.S. District Court in Nevada are five cases against Sempra Energy, Sempra Commodities, the Sempra Utilities and various other companies, which make similar allegations to those in the state proceedings, four of which also include conspiracy allegations similar to those made in the Continental Forge litigation. The court dismissed four of these actions in 2005, determining that the FERC had exclusive jurisdiction to resolve the claims. The remaining case, which includes conspiracy allegations, was stayed. In September 2007, the Ninth Circuit Court of Appeals reversed the dismissal and returned the cases to the District Court for further proceedings.
FERC Refund Proceedings
The FERC is investigating prices charged to buyers in the California Power Exchange (PX) and Independent System Operator (ISO) markets by various electric suppliers. In December 2002, a FERC Administrative Law Judge (ALJ) issued preliminary findings indicating that the PX and ISO owe power suppliers $1.2 billion for the October 2, 2000 through June 20, 2001 period (the $3.0 billion that the California PX and ISO still owe energy companies less $1.8 billion that the energy companies charged California customers in excess of the preliminarily determined competitive market clearing prices). In March 2003, the FERC adopted its ALJ's findings, but changed the calculation of the refund by basing it on a different estimate of natural gas prices, which would increase the refund obligations from $1.8 billion to more than $3 billion for the same time period.
Various parties appealed the FERC's order to the Ninth Circuit Court of Appeals. In August 2006, the Court of Appeals held that the FERC had properly established October 2, 2000 through June 20, 2001 as the refund period and had properly excluded certain bilateral transactions between sellers and the DWR from the refund proceedings. However, the court also held that the FERC erred in excluding certain multi-day transactions from the refund proceedings. Finally, while the court upheld the FERC's decision not to extend the refund proceedings to the summer period (prior to October 2, 2000), it found that the FERC had erred in not considering other remedies, such as disgorgement of profits, for tariff violations that are alleged to have occurred prior to October 2, 2000. The Court of Appeals remanded the matter to the FERC for further proceedings. In November 2007, Sempra Commodities and other entities filed requests for rehearing of the Court of Appeals’ August 2006 decision. In August 2007, the Ninth Circuit Court of Appeals issued a decision reversing and remanding FERC orders declining to provide refunds in a related proceeding regarding short-term bilateral sales up to one month in the Pacific Northwest. The court found that some of the short-term sales between the DWR and various sellers (including Sempra Commodities) that had previously been excluded from the refund proceeding involving sales in the ISO and PX markets in California, were within the scope of the Pacific Northwest refund proceeding. In December 2007, Sempra Commodities and other sellers filed requests for rehearing of the Court of Appeals’ August 2007 decision. It is possible that on remand, the FERC could order refunds for short-term sales to the DWR in the Pacific Northwest refund proceeding.
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Other Litigation
In October 2007, Southern California experienced catastrophic wildfires. The causes of many of these fires remain under investigation, including the possible role of SDG&E power lines affected by unusually high winds. In November 2007, the California Department of Forestry and Fire Protection (Cal Fire) issued a press release stating that power lines caused three of the fires in San Diego County and that together these three fires burned more than 200,000 acres and destroyed approximately 1,900 structures. Cal Fire is expected to issue a final report, and the CPUC’s Consumer Protection and Safety Division, which is also investigating the fires, is also expected to issue a report. Six lawsuits, four of which seek to be designated as class actions, have been filed against SDG&E in San Diego County Superior Court seeking unspecified amounts for damages relating to the fires. One of the lawsuits also names Sempra Energy as a defendant. The lawsuits assert that SDG&E improperly designed and maintained its power lines and failed to adequately clear adjacent vegetation. The company has approximately $1 billion in liability insurance and has notified its insurers of the lawsuits.
Nuclear Insurance
SDG&E and the other owners of the San Onofre Nuclear Generating Station (SONGS) have insurance to respond to nuclear liability claims related to SONGS. The insurance provides coverage of $300 million, the maximum amount available, and includes coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $10.5 billion of secondary financial protection. Should any of the licensed/commercial reactors in the United States experience a nuclear liability loss that exceeds the $300 million insurance limit, all utilities owning nuclear reactors could be assessed to provide the secondary financial protection. SDG&E's total share would be up to $40 million, subject to an annual maximum assessment of $6 million, unless a default were to occur by any other SONGS owner. In the event the secondary financial protection limit were insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.
SDG&E and the other owners of SONGS have $2.75 billion of nuclear property, decontamination and debris removal insurance and up to $490 million for outage expenses and replacement power costs incurred because of accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks and $2.8 million per week for up to 110 additional weeks, after a waiting period of 12 weeks. The insurance is provided through a mutual insurance company, through which insured members are subject to retrospective premium assessments (up to $8.6 million in SDG&E's case).
The nuclear property insurance program, subscribed to by members of the nuclear power generating industry, includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $3.24 billion. This limit is the maximum amount to be paid to members who sustain losses or damages from these non-certified terrorist acts.
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ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the financial statements contained in this Form 10-Q and "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" contained in the company's 2007 Annual Report on Form 10-K (Annual Report).
RESULTS OF OPERATIONS
Revenues and Cost of Sales
Electric revenues increased for the three months ended March 31, 2008 compared to the corresponding period in 2007 primarily due to higher cost of electric fuel and purchased power and higher authorized transmission margin.
As a final decision in the 2008 General Rate Case (GRC) was not issued by the California Public Utilities Commission (CPUC) by March 31, 2008, revenues for the first quarter of 2008 associated with CPUC-regulated operations were consistent with the 2007 CPUC-authorized revenue established by the 2004 Cost of Service decision.
Although the current regulatory framework provides that the cost of natural gas purchased for core customers be passed through to the customers on a substantially concurrent basis, SDG&E's natural gas procurement Performance-Based Regulation (PBR) mechanism, which was in effect through March 31, 2008, allowed the company to share in the savings or costs from buying natural gas for its customers below or above market-based monthly benchmarks. The mechanism permitted full recovery of commodity procurement costs within a tolerance band around the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. Further discussion is provided in Notes 1 and 11 of the Notes to Consolidated Financial Statements in the Annual Report.
The tables below summarize the electric and natural gas volumes and revenues by customer class for the three-month periods ended March 31.
Electric Distribution and Transmission
(Volumes in millions of kilowatt-hours, dollars in millions)
2008
2007
Volumes
Revenue
Volumes
Revenue
Residential
2,009
$
220
1,960
$
249
Commercial
1,687
160
1,683
185
Industrial
556
43
525
48
Direct access
765
23
778
28
Street and highway lighting
26
3
25
3
5,043
449
4,971
513
Balancing accounts and other
52
(43
)
Total
$
501
$
470
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Although commodity costs associated with long-term contracts allocated to SDG&E from the California Department of Water Resources (and the revenues to recover those costs) are not included in the Statements of Consolidated Income, the associated volumes and distribution revenues are included in the above table.
Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Natural Gas Sales
Transportation and Exchange
Total
Volumes
Revenue
Volumes
Revenue
Volumes
Revenue
2008:
Residential
14
$
180
--
$
--
14
$
180
Commercial and industrial
5
56
2
3
7
59
Electric generation plants
--
--
18
7
18
7
19
$
236
20
$
10
39
246
Balancing accounts and other
(1
)
Total
$
245
2007:
Residential
14
$
172
--
$
--
14
$
172
Commercial and industrial
5
55
1
2
6
57
Electric generation plants
--
--
14
10
14
10
19
$
227
15
$
12
34
239
Balancing accounts and other
--
Total
$
239
Income Taxes
Income tax expense was$32 million and $38 million for the three months ended March 31, 2008 and 2007, respectively, and the effective income tax rates were 30 percent and 38 percent, respectively. The decrease in income tax expense for the three months ended March 31, 2008 was due primarily to the favorable resolution of prior years' income tax issues in 2008.
Net Income
Net income for SDG&E increased by $12 million (19%) in the three months ended March 31, 2008 to $75 million. The increase was primarily due to the favorable resolution of prior years' income tax issues in 2008.
CAPITAL RESOURCES AND LIQUIDITY
The company’s utility operations generally are the major source of liquidity. In addition, cash requirements can be met through the issuance of short-term and long-term debt. Cash requirements primarily consist of capital expenditures for utility plant.
At March 31, 2008, the company had $31 million in unrestricted cash and cash equivalents, and $467 million in available unused credit on its committed line,which is shared with SoCalGas and is discussed more fully in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. Management believes thatthese amounts and cash flows from operations andsecurity issuances will be adequate to finance capital expenditures and meet liquidity requirements and other commitments. Management continues to regularly monitor the company’s ability to finance
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the needs of its operating, investing and financing activities in a manner consistent with its intention to maintain strong, investment-quality credit ratings.
As a result of the company's projected capital expenditure program, SDG&E has elected to suspend the payment of dividends on its common stock to Sempra Energy, and the level of future common dividends may be affected in order to maintain SDG&E's authorized capital structure during periods of increased capital expenditures.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities increased by $12 million (5%) to $278 million for 2008. The change was primarily due to a $4 million increase in accounts payable in 2008 compared to a $36 million decrease in 2007 and a $28 million higher decrease in inventory, offset by a $57 million lower increase in overcollected regulatory balancing accounts.
For the three months ended March 31, 2008,the company made contributions of a negligible amount and $3 million to the pension plan and other postretirement benefit plans, respectively.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities increased by $331 million (238%) to $470 million for 2008. The increase was primarily due to the purchase of $236 million of industrial development bonds and a $78 million increase in capital expenditures.
Significant capital expenditures in 2008 are expected to include $700 million for additions to the company's natural gas and electric distribution and electric transmission and generation systems, and advanced metering infrastructure. These expenditures are expected to be financed by cash flows from operations and security issuances. These amounts exclude capital expenditures of OMEC LLC.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by (used in) financing activities totaled $65 million for 2008 and $(93) million for 2007. The change was primarily due to a $33 million increase in short-term debt in 2008 compared to a decrease of $72 million in 2007 and $47 million of long-term debt issuances in 2008.
COMMITMENTS
At March 31, 2008, there were no significant changes to the commitments that were disclosed in the Annual Report, except for a decrease of $187 million related to the transfer of SDG&E’s natural gas supply portfolio to SoCalGas as part of the Omnibus Gas Settlements discussed in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the company will depend primarily on the ratemaking and regulatory process, electric and natural gas industry restructuring, and the changing energy marketplace. Performance will also depend on the CPUC’s final decision regarding the 2008 General Rate Case and the successful completion of capital projects that are discussed in various places in this report and in the Annual Report. These factors are discussed in Note 5 of the Notes to Condensed Consolidated
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Financial Statements herein and in Notes 10 and 11 of the Notes to Consolidated Financial Statements in the Annual Report.
Litigation
Note 6 of the Notes to Condensed Consolidated Financial Statements herein and Note 12 of the Notes to Consolidated Financial Statements in the Annual Report describe litigation, the ultimate resolution of which could have a material adverse effect on future performance.
Industry Developments
Note 5of the Notes to Condensed Consolidated Financial Statements herein andNotes 10 and 11 of the Notes to Consolidated Financial Statements in the Annual Report describe electric and natural gas regulation and rates, and other pending proceedings and investigations.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain accounting policies are viewed by management as critical because their application is the most relevant, judgmental and/or material to the company's financial position and results of operations, and/or because they require the use of material judgments and estimates. These accounting policies are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.
The company's significant accounting policies are described in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
NEW ACCOUNTING STANDARDS
Recently issued pronouncements that have had or may have a significant effect on the company's financial statements are described in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no significant changes in the risk issues affecting the company subsequent to those discussed in the Annual Report.
As of March 31, 2008, the total Value at Risk of SDG&E's positions was not material.
ITEM 4. CONTROLS AND PROCEDURES
Company management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can
21
provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures. In addition, the company consolidates a variable interest entity as defined in Financial Accounting Standards Board Interpretation No. 46(R) that it does not control or manage and consequently, its disclosure controls and procedures with respect to this entity are necessarily limited to oversight or monitoring controls that the company has implemented to provide reasonable assurance that the objectives of the company's disclosure controls and procedures as described above are met.
There have been no changes in the company's internal control over financial reporting during the company's most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the company's internal control over financial reporting.
The company evaluates the effectiveness of its internal control over financial reporting based on the framework inInternal Control--Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures as of March 31, 2008, the end of the period covered by this report. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures were effective at the reasonable assurance level.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except for the matters described in Notes 5 and 6 of the Notes to Condensed Consolidated Financial Statements herein, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses.
ITEM 1A. RISK FACTORS
There have been no material changes from risk factors as previously disclosed in the company's 2007 Annual Report on Form 10-K.
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ITEM 6. EXHIBITS
Exhibit 10 - Material Contracts
10.1
Indemnity Agreement, dated as of April 1, 2008, between Sempra Energy, Pacific Enterprises, Enova Corporation and The Royal Bank of Scotland plc. (March 31, 2008 Sempra Energy Form 10-Q, Exhibit 10.2).
Exhibit 12 - Computation of ratios
12.1
Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Exhibit 31 -- Section 302 Certifications
31.1
Statement of Registrant's Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2
Statement of Registrant's Chief Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Exhibit 32 -- Section 906 Certifications
32.1
Statement of Registrant's Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2
Statement of Registrant's Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
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SIGNATURE
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.
SAN DIEGO GAS & ELECTRIC COMPANY, (Registrant)
Date: May 2, 2008
By: /s/ Dennis V. Arriola
Dennis V. Arriola Senior Vice President and Chief Financial Officer
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