|
SEMPRA ENERGY FORM 10-Q
SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q
SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q
TABLE OF CONTENTS
|
||
|
Page
|
||
|
Information Regarding Forward-Looking Statements
|
4
|
|
|
PART I – FINANCIAL INFORMATION
|
||
|
Item 1.
|
Financial Statements
|
5
|
|
Item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
66
|
|
Item 3.
|
Quantitative and Qualitative Disclosures About Market Risk
|
96
|
|
Item 4.
|
Controls and Procedures
|
97
|
|
PART II – OTHER INFORMATION
|
||
|
Item 1.
|
Legal Proceedings
|
98
|
|
Item 1A.
|
Risk Factors
|
98
|
|
Item 6.
|
Exhibits
|
99
|
|
Signatures
|
101
|
|
This combined Form 10-Q is separately filed by Sempra Energy, San Diego Gas & Electric Company and Southern California Gas Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representation whatsoever as to any other company.
You should read this report in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Part I – Item 1 sections are provided for each reporting company, except for the Notes to Condensed Consolidated Financial Statements. The Notes to Condensed Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Part I – Item 1 are combined for the reporting companies.
We make statements in this report that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. These forward-looking statements represent our estimates and assumptions only as of the filing date of this report. We assume no obligation to update or revise any forward-looking statement as a result of new information, future events or other factors.
In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “forecasts,” “contemplates,” “intends,” “depends,” “should,” “could,” “would,” “will,” “may,” “potential,” “target,” “pursue,” “goals,” “outlook,” “maintain,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, opportunities, projections, initiatives, objectives or intentions, we are making forward-looking statements.
Factors, among others, that could cause our actual results and future actions to differ materially from those described in forward-looking statements include
|
§
|
local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments;
|
|
§
|
actions and the timing of actions, including issuances of permits to construct and licenses for operation, by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, Atomic Safety and Licensing Board, California Energy Commission, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;
|
|
§
|
capital markets conditions, including the availability of credit and the liquidity of our investments;
|
|
§
|
the timing and success of business development efforts and construction, maintenance and capital projects, including risks in obtaining permits, licenses, certificates and other authorizations on a timely basis and risks in obtaining adequate and competitive financing for such projects;
|
|
§
|
inflation, interest and exchange rates;
|
|
§
|
the impact of benchmark interest rates, generally Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital;
|
|
§
|
energy markets, including the timing and extent of changes and volatility in commodity prices;
|
|
§
|
the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures and the decommissioning of San Onofre Nuclear Generating Station (SONGS);
|
|
§
|
weather conditions, natural disasters, catastrophic accidents, and conservation efforts;
|
|
§
|
risks inherent with nuclear power facilities and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in, or operating costs of, the nuclear facility due to an extended outage and facility closure, and increased regulatory oversight;
|
|
§
|
risks that our partners or counterparties will be unable or unwilling to fulfill their contractual commitments;
|
|
§
|
risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest;
|
|
§
|
wars, terrorist attacks that threaten system operations and critical infrastructure, and cybersecurity threats to the energy grid and the confidentiality of our proprietary information and the personal information of our customers;
|
|
§
|
business, regulatory, environmental and legal decisions and requirements;
|
|
§
|
expropriation of assets by foreign governments and title and other property disputes;
|
|
§
|
the impact on reliability of San Diego Gas & Electric Company’s (SDG&E) electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources;
|
|
§
|
the impact on competitive customer rates of the growth in distributed and local power generation and the corresponding decrease in demand for power delivered through SDG&E’s electric transmission and distribution system;
|
|
§
|
the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements;
|
|
§
|
the resolution of litigation; and
|
|
§
|
other uncertainties, all of which are difficult to predict and many of which are beyond our control.
|
We caution you not to rely unduly on any forward-looking statements. You should review and consider carefully the risks, uncertainties and other factors that affect our business as described in this report and in our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission.
PART I – FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SEMPRA ENERGY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PRINCIPLES OF CONSOLIDATION
Sempra Energy
Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are
|
§
|
San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate, reportable segments;
|
|
§
|
Sempra International, which includes our Sempra South American Utilities and Sempra Mexico reportable segments; and
|
|
§
|
Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural Gas reportable segments.
|
We provide descriptions of each of our segments in Note 12.
We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.
Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova further in Note 5 under “Shareholders’ Equity and Noncontrolling Interests – Sale of Noncontrolling Interests.”
Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Note 4 herein and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2013 (the Annual Report), which includes the combined reports for Sempra Energy, SDG&E and SoCalGas.
SDG&E
SDG&E’s Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss in Note 5 under “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.
SoCalGas
SoCalGas’ Condensed Consolidated Financial Statements include its accounts and the de minimus accounts of inactive subsidiaries. SoCalGas’ common stock is wholly owned by Pacific Enterprises (PE), which is a wholly owned subsidiary of Sempra Energy.
BASIS OF PRESENTATION
This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.
We have prepared the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. 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. We evaluated events and transactions that occurred after March 31, 2014 through the date the financial statements were issued and, 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.
All December 31, 2013 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2013 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the Securities and Exchange Commission.
You should read the information in this Quarterly Report in conjunction with the Annual Report.
Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas México, S. de R.L. de C.V. (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Sempra Natural Gas’ Mobile Gas and Willmut Gas, and Sempra Mexico’s Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes, except for the adoption of new accounting standards as we discuss in Note 2.
We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures.
SEMPRA ENERGY, SDG&E AND SOCALGAS
Accounting Standards Update (ASU) 2013-11,
“
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists
”
(ASU 2013-11):
ASU 2013-11 provides explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward. If a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes, an entity is required to present the unrecognized tax benefit in the financial statements as a liability instead of combined with deferred tax assets.
We adopted ASU 2013-11 on January 1, 2014 as required, and it did not significantly affect our financial condition, results of operations or cash flows.
SEMPRA RENEWABLES
In March 2014, Sempra Renewables formed a joint venture with Consolidated Edison Development (ConEdison Development), a non-related party, by selling a 50-percent interest in its 250-megawatt (MW) Copper Mountain Solar 3 solar power facility for $66 million in cash, net of $2 million cash sold, subject to a final purchase price adjustment that we do not expect to be significant. Sempra Renewables recognized a pretax gain on the sale of $27 million ($16 million after-tax), included in Gain on Sale of Equity Interest and Assets on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2014. Our remaining 50-percent interest in Copper Mountain Solar 3 is now accounted for under the equity method. We measured our equity method investment in Copper Mountain Solar 3 at historical cost and, therefore, no portion of the gain was attributable to a remeasurement of the retained investment to fair value.
The following table summarizes the deconsolidation:
|
DECONSOLIDATION OF SUBSIDIARY
|
|||
|
(Dollars in millions)
|
|||
|
|
Copper Mountain Solar 3
|
||
|
Proceeds from sale, net of negligible transaction costs
|
$
|
68
|
|
|
Cash
|
|
(2)
|
|
|
Property, plant and equipment, net
|
|
(247)
|
|
|
Other assets
|
|
(11)
|
|
|
Accounts payable and accrued expenses
|
|
82
|
|
|
Long-term debt, including current portion
|
|
97
|
|
|
Other long-term liabilities
|
|
3
|
|
|
Accumulated other comprehensive income
|
|
(2)
|
|
|
Gain on sale of equity interest and assets
|
|
(27)
|
|
|
Equity method investment upon deconsolidation
|
$
|
(39)
|
|
|
|
|
||
SEMPRA NATURAL GAS
Mesquite Power Sale
In February 2013, Sempra Natural Gas sold one 625-MW block of its 1,250-MW Mesquite Power natural gas-fired power plant in Arizona, including a portion related to common plant, for approximately $371 million in cash to the Salt River Project Agricultural Improvement and Power District (SRP). We recognized a pretax gain on the sale of $74 million ($44 million after-tax), included in Gain on Sale of Equity Interest and Assets on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2013. In connection with the sale, we entered into a 20-year operations and maintenance agreement with SRP on February 28, 2013, whereby SRP assumed plant operations and maintenance of the facility, including our remaining 625-MW block. We provide additional information concerning the operations and maintenance agreement in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Asset Held for Sale, Power Plant
In January 2014, management approved a formal plan to market and sell the remaining 625-MW block of the Mesquite Power plant. We expect to complete the sale in 2014.
We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next twelve months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs, and we stop recording depreciation expense on the asset.
At March 31, 2014, the carrying amount of the major classes of assets and related liability held for sale associated with the plant includes the following:
The estimated fair value, including estimated costs to sell, exceeds the carrying amount at March 31, 2014.
We provide additional information concerning all of our equity method investments in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
SEMPRA SOUTH AMERICAN UTILITIES
Sempra South American Utilities previously owned 43 percent of two Argentine natural gas utility holding companies, Sodigas Pampeana and Sodigas Sur. In the first quarter of 2013, we recorded a noncash impairment charge of $10 million ($7 million after-tax) to reduce the carrying value of our investments to estimated fair value at that time. The net charge is reported in Equity Earnings, Net of Income Tax on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2013.
SEMPRA RENEWABLES
In March 2014, Sempra Renewables and ConEdison Development entered into an agreement to partner in four solar projects in California. The projects include ConEdison Development’s CED California Holdings, LLC portfolio, which consists of the 50-MW Alpaugh 50, the 20-MW Alpaugh North and the 20-MW White River 1 facilities in Tulare County, and the 20-MW Corcoran 1 facility in Kings County (collectively, the California solar partnership). The renewable power from all of the projects has been sold under long-term contracts. The agreement is subject to regulatory approvals. Upon consummation of the transaction under the agreement, Sempra Renewables and ConEdison Development will each own a 50-percent interest in the four solar facilities.
Sempra Renewables invested $51 million (which included $39 million that was deconsolidated upon the formation of the Copper Mountain Solar 3 joint venture, as we discuss in Note 3) and $5 million in its solar and wind generation joint ventures in the three months ended March 31, 2014 and 2013, respectively.
RBS SEMPRA COMMODITIES
RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses previously owned by us. We and our partner in the joint venture, The Royal Bank of Scotland plc (RBS), sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and early 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs, if any, in Equity Earnings, Before Income Tax on our Condensed Consolidated Statements of Operations.
The investment balance of $73 million at March 31, 2014 reflects remaining distributions expected to be received from the partnership in accordance with provisions of a 2011 agreement between us and RBS that addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 11 under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.
We recorded no equity earnings or losses related to the partnership for the three months ended March 31, 2014 and 2013.
U.S. TREASURY GRANTS
At December 31, 2012, we had receivables for U.S. Treasury grants based on eligible costs at certain of our renewable generating facilities. During the first quarter of 2013, the federal government imposed automatic federal budget cuts, known as “sequestration,” as required by The Budget Control Act of 2011. As a result, we recorded a reduction to our grants receivable of $23 million and a reversal of income tax benefit of $5 million during the first quarter of 2013. The remaining grants receivable were received in the second and third quarters of 2013.
INVENTORIES
The components of inventories by segment are as follows:
|
INVENTORY BALANCES
|
|||||||||||||||||
|
(Dollars in millions)
|
|||||||||||||||||
|
|
|
Natural Gas
|
Liquefied Natural Gas
|
Materials and Supplies
|
Total
|
||||||||||||
|
|
|
March 31,
2014
|
December 31,
2013
|
March 31,
2014
|
December 31,
2013
|
March 31,
2014
|
December 31,
2013
|
March 31,
2014
|
December 31,
2013
|
||||||||
|
SDG&E
|
$
|
4
|
$
|
3
|
$
|
―
|
$
|
―
|
$
|
72
|
$
|
83
|
$
|
76
|
$
|
86
|
|
|
SoCalGas
|
|
17
|
|
42
|
|
―
|
|
―
|
|
28
|
|
27
|
|
45
|
|
69
|
|
|
Sempra South American
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utilities
|
|
―
|
|
―
|
|
―
|
|
―
|
|
39
|
|
40
|
|
39
|
|
40
|
|
|
Sempra Mexico
|
|
―
|
|
―
|
|
4
|
|
3
|
|
9
|
|
9
|
|
13
|
|
12
|
|
|
Sempra Renewables
|
|
―
|
|
―
|
|
―
|
|
―
|
|
2
|
|
2
|
|
2
|
|
2
|
|
|
Sempra Natural Gas
|
|
16
|
|
68
|
|
5
|
|
5
|
|
1
|
|
5
|
|
22
|
|
78
|
|
|
Sempra Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
$
|
37
|
$
|
113
|
$
|
9
|
$
|
8
|
$
|
151
|
$
|
166
|
$
|
197
|
$
|
287
|
|
|
|
|
||||||||||||||||
GOODWILL
We discuss goodwill in Notes 1 and 3 of the Notes to Consolidated Financial Statements in the Annual Report. The decrease in goodwill from $1.024 billion at December 31, 2013 to $999 million at March 31, 2014 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in Other Comprehensive Income (Loss).
VARIABLE INTEREST ENTITIES (VIE)
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess
|
§
|
the purpose and design of the VIE;
|
|
§
|
the nature of the VIE’s risks and the risks we absorb;
|
|
§
|
the power to direct activities that most significantly impact the economic performance of the VIE; and
|
|
§
|
the obligation to absorb losses or right to receive benefits that could be significant to the VIE.
|
SDG&E
Tolling Agreements
SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based upon our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which we consider the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE, as we discuss below.
Otay Mesa VIE
SDG&E has an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase the power plant at the end of the contract term in 2019, or upon earlier termination of the purchased-power agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, under certain circumstances, it may be required to purchase the power plant at a predetermined price, which we refer to as the put option.
The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE’s equity of $87 million at March 31, 2014 and $91 million at December 31, 2013 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.
OMEC LLC has a loan outstanding of $332 million at March 31, 2014, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.
Other Variable Interest Entities
SDG&E’s power procurement is subject to reliability requirements that may require SDG&E to enter into various power purchase arrangements which include variable interests. SDG&E evaluates the respective entities to determine if variable interests exist and, based on the qualitative and quantitative analyses described above, if SDG&E, and thereby Sempra Energy, is the primary beneficiary. SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary at March 31, 2014. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates.
Sempra Energy’s other operating units also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based upon the qualitative and quantitative analyses described above. Certain of these entities are service companies that are VIEs. As the primary beneficiary of these service companies, we consolidate them. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.
The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on the table below generally correspond to SDG&E’s Condensed Consolidated Statements of Operations.
|
AMOUNTS ASSOCIATED WITH OTAY MESA VIE
|
||||
|
(Dollars in millions)
|
||||
|
|
Three months ended March 31,
|
|||
|
|
2014
|
2013
|
||
|
|
|
|
|
|
|
Operating revenues
|
|
|
|
|
|
Electric
|
$
|
―
|
$
|
(1)
|
|
Natural gas
|
|
―
|
|
―
|
|
Total operating revenues
|
|
―
|
|
(1)
|
|
Operating expenses
|
|
|
|
|
|
Cost of electric fuel and purchased power
|
|
(18)
|
|
(17)
|
|
Operation and maintenance
|
|
5
|
|
17
|
|
Depreciation and amortization
|
|
7
|
|
7
|
|
Total operating expenses
|
|
(6)
|
|
7
|
|
Operating income (loss)
|
|
6
|
|
(8)
|
|
Interest expense
|
|
(4)
|
|
(3)
|
|
Income (loss) before income taxes/Net income (loss)
|
|
2
|
|
(11)
|
|
(Earnings) losses attributable to noncontrolling interest
|
|
(2)
|
|
11
|
|
Earnings
|
$
|
―
|
$
|
―
|
We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
PENSION AND OTHER POSTRETIREMENT BENEFITS
Net Periodic Benefit Cost
The following three tables provide the components of net periodic benefit cost:
|
NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
|
||||||||
|
(Dollars in millions)
|
||||||||
|
|
Pension Benefits
|
Other Postretirement Benefits
|
||||||
|
|
Three months ended March 31,
|
Three months ended March 31,
|
||||||
|
|
2014
|
2013
|
2014
|
2013
|
||||
|
Service cost
|
$
|
26
|
$
|
27
|
$
|
6
|
$
|
7
|
|
Interest cost
|
|
41
|
|
37
|
|
12
|
|
11
|
|
Expected return on assets
|
|
(43)
|
|
(40)
|
|
(16)
|
|
(15)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
2
|
|
1
|
|
(1)
|
|
(1)
|
|
Actuarial loss
|
|
5
|
|
15
|
|
―
|
|
2
|
|
Settlement
|
|
3
|
|
―
|
|
―
|
|
―
|
|
Regulatory adjustment
|
|
(24)
|
|
(32)
|
|
―
|
|
2
|
|
Total net periodic benefit cost
|
$
|
10
|
$
|
8
|
$
|
1
|
$
|
6
|
|
NET PERIODIC BENEFIT COST – SDG&E
|
||||||||
|
(Dollars in millions)
|
||||||||
|
|
Pension Benefits
|
Other Postretirement Benefits
|
||||||
|
|
Three months ended March 31,
|
Three months ended March 31,
|
||||||
|
|
2014
|
2013
|
2014
|
2013
|
||||
|
Service cost
|
$
|
8
|
$
|
8
|
$
|
2
|
$
|
2
|
|
Interest cost
|
|
11
|
|
10
|
|
2
|
|
2
|
|
Expected return on assets
|
|
(14)
|
|
(13)
|
|
(3)
|
|
(2)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
Prior service cost
|
|
―
|
|
―
|
|
1
|
|
1
|
|
Actuarial loss
|
|
1
|
|
4
|
|
―
|
|
―
|
|
Regulatory adjustment
|
|
(5)
|
|
(8)
|
|
(2)
|
|
―
|
|
Total net periodic benefit cost
|
$
|
1
|
$
|
1
|
$
|
―
|
$
|
3
|
|
NET PERIODIC BENEFIT COST – SOCALGAS
|
||||||||
|
(Dollars in millions)
|
||||||||
|
|
Pension Benefits
|
Other Postretirement Benefits
|
||||||
|
|
Three months ended March 31,
|
Three months ended March 31,
|
||||||
|
|
2014
|
2013
|
2014
|
2013
|
||||
|
Service cost
|
$
|
16
|
$
|
16
|
$
|
4
|
$
|
4
|
|
Interest cost
|
|
25
|
|
23
|
|
9
|
|
9
|
|
Expected return on assets
|
|
(26)
|
|
(25)
|
|
(13)
|
|
(12)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
2
|
|
1
|
|
(2)
|
|
(2)
|
|
Actuarial loss
|
|
2
|
|
9
|
|
―
|
|
2
|
|
Regulatory adjustment
|
|
(19)
|
|
(24)
|
|
2
|
|
2
|
|
Total net periodic benefit cost
|
$
|
―
|
$
|
―
|
$
|
―
|
$
|
3
|
Benefit Plan Contributions
The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2014:
|
|
Sempra Energy
|
|
|
|||
|
(Dollars in millions)
|
Consolidated
|
SDG&E
|
SoCalGas
|
|||
|
Contributions through March 31, 2014:
|
|
|
|
|
|
|
|
Pension plans
|
$
|
15
|
$
|
1
|
$
|
2
|
|
Other postretirement benefit plans
|
|
1
|
|
―
|
|
―
|
|
Total expected contributions in 2014:
|
|
|
|
|
|
|
|
Pension plans
|
$
|
187
|
$
|
65
|
$
|
86
|
|
Other postretirement benefit plans
|
|
12
|
|
9
|
|
―
|
RABBI TRUST
In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $476 million and $506 million at March 31, 2014 and December 31, 2013, respectively.
EARNINGS PER SHARE
The following table provides the per share computations for our earnings for the three months ended March 31, 2014 and 2013. Basic earnings per common share (EPS) is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.
|
EARNINGS PER SHARE COMPUTATIONS
|
|||||
|
(Dollars in millions, except per share amounts; shares in thousands)
|
|||||
|
|
|
Three months ended March 31,
|
|||
|
|
|
2014
|
2013
|
||
|
Numerator:
|
|
|
|
|
|
|
Earnings/Income attributable to common shares
|
$
|
247
|
$
|
178
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
Weighted-average common shares
|
|
|
|
|
|
|
|
outstanding for basic EPS
|
|
245,277
|
|
243,294
|
|
Dilutive effect of stock options, restricted
|
|
|
|
|
|
|
|
stock awards and restricted stock units
|
|
4,392
|
|
4,240
|
|
Weighted-average common shares
|
|
|
|
|
|
|
|
outstanding for diluted EPS
|
|
249,669
|
|
247,534
|
|
|
|
|
|
|
|
|
Earnings per share:
|
|
|
|
|
|
|
Basic
|
$
|
1.01
|
$
|
0.73
|
|
|
Diluted
|
$
|
0.99
|
$
|
0.72
|
|
The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive upon the assumed exercise of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). We had no such antidilutive stock options outstanding during the three months ended March 31, 2014 and 2013.
During the three months ended March 31, 2014 and 2013, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.
The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were no antidilutive RSUs and 774 antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months ended March 31, 2014 and 2013, respectively. There were no such antidilutive RSAs and 3,090 such antidilutive RSAs for the three months ended March 31, 2014 and 2013, respectively.
Each performance-based RSU represents the right to receive between zero and 1.5 shares (2.0 shares for awards granted in 2014) of Sempra Energy common stock based on total shareholder return or EPS growth. RSU awards vest based on Sempra Energy’s four-year cumulative total shareholder return compared to the Standard & Poor’s (S&P) 500 Utilities Index, as follows:
Beginning in January 2014, we issued performance-based RSUs representing the right to receive between zero and 2.0 shares of Sempra Energy common stock based on Sempra Energy’s four-year compound EPS annual growth rate beginning January 1, 2014 and ending on December 31, 2017, as follows:
RSAs and those RSUs that are solely service-based have a maximum potential of 100 percent vesting and have the same dividend equivalent rights as performance-based RSUs. We include our performance-based RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Performance-based RSUs and RSAs may be excluded from potential dilutive shares because performance goals are currently not met. Due to market fluctuations of both Sempra Energy stock and the comparative index, dilutive performance-based RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, and those RSUs that are solely service-based in potential dilutive shares at 100 percent. The maximum excluded RSAs and RSUs, assuming performance goals were met at maximum levels, were 1,142,023 and 1,659,995 for the three months ended March 31, 2014 and 2013, respectively.
SHARE-BASED COMPENSATION
We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $7 million and $6 million for the three months ended March 31, 2014 and 2013, respectively. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s board of directors granted 443,791 performance-based RSUs and 77,492 service-based RSUs during the three months ended March 31, 2014, primarily in January. Of the 443,791 performance-based RSUs granted, 355,278 vest based on total shareholder return performance and 88,513 vest based on EPS growth rate performance. During the three months ended March 31, 2014, IEnova issued 136,996 RSUs from the IEnova 2013 Long-Term Incentive Plan.
CAPITALIZED FINANCING COSTS
Capitalized financing costs include capitalized interest costs and, primarily at the California Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects.
Pipeline projects currently under construction by Sempra Mexico that are both regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and meet U.S. GAAP regulatory accounting requirements record the impact of AFUDC related to equity. Beginning in the fourth quarter of 2013, Sempra Mexico began recording AFUDC related to equity for its Sonora Pipeline project, which was $9 million for the three months ended March 31, 2014.
The following table shows capitalized financing costs for the three months ended March 31, 2014 and 2013.
|
CAPITALIZED FINANCING COSTS
|
|||||
|
(Dollars in millions)
|
|||||
|
|
|
Three months ended March 31,
|
|||
|
|
|
2014
|
2013
|
||
|
Sempra Energy Consolidated:
|
|
|
|
|
|
|
AFUDC related to debt
|
$
|
6
|
$
|
6
|
|
|
AFUDC related to equity
|
|
25
|
|
15
|
|
|
Other capitalized financing costs
|
|
8
|
|
5
|
|
|
Total Sempra Energy Consolidated
|
$
|
39
|
$
|
26
|
|
|
SDG&E:
|
|
|
|
|
|
|
AFUDC related to debt
|
$
|
4
|
$
|
4
|
|
|
AFUDC related to equity
|
|
11
|
|
10
|
|
|
Total SDG&E
|
$
|
15
|
$
|
14
|
|
|
SoCalGas:
|
|
|
|
|
|
|
AFUDC related to debt
|
$
|
2
|
$
|
2
|
|
|
AFUDC related to equity
|
|
5
|
|
5
|
|
|
Total SoCalGas
|
$
|
7
|
$
|
7
|
|
COMPREHENSIVE INCOME
The following tables present the changes in Accumulated Other Comprehensive Income (Loss) (AOCI) by component and amounts reclassified out of AOCI to net income, excluding amounts attributable to noncontrolling interests:
|
CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
|
|||||||||||
|
SEMPRA ENERGY CONSOLIDATED
|
|||||||||||
|
(Dollars in millions)
|
|||||||||||
|
|
|
Three months ended March 31, 2014 and 2013
|
|||||||||
|
|
|
|
|
Pension and Other
|
|
|
|
|
|||
|
|
|
|
|
Postretirement Benefits
|
|
|
|
|
|||
|
|
|
Foreign
|
|
|
|
|
|
Total
|
|||
|
|
|
Currency
|
Unamortized
|
Unamortized
|
|
Accumulated Other
|
|||||
|
|
|
Translation
|
Net Actuarial
|
Prior Service
|
Financial
|
Comprehensive
|
|||||
|
|
|
Adjustments
|
Gain (Loss)
|
Credit
|
Instruments
|
Income (Loss)
|
|||||
|
2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2013
|
$
|
(129)
|
$
|
(73)
|
$
|
―
|
$
|
(26)
|
$
|
(228)
|
|
|
Other comprehensive loss before
|
|
|
|
|
|
|
|
|
|
|
|
|
reclassifications
|
|
(43)
|
|
―
|
|
―
|
|
(14)
|
|
(57)
|
|
|
Amounts reclassified from accumulated other
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive income
|
|
―
|
|
3
|
|
―
|
|
9
|
|
12
|
|
|
Net other comprehensive income (loss)
|
|
(43)
|
|
3
|
|
―
|
|
(5)
|
|
(45)
|
|
|
Balance as of March 31, 2014
|
$
|
(172)
|
$
|
(70)
|
$
|
―
|
$
|
(31)
|
$
|
(273)
|
|
|
2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2012
|
$
|
(240)
|
$
|
(102)
|
$
|
1
|
$
|
(35)
|
$
|
(376)
|
|
|
Other comprehensive income (loss) before
|
|
|
|
|
|
|
|
|
|
|
|
|
reclassifications
|
|
10
|
|
―
|
|
―
|
|
(16)
|
|
(6)
|
|
|
Amounts reclassified from accumulated other
|
|
|
|
|
|
|
|
|
|
|
|
|
comprehensive income
|
|
―
|
|
3
|
|
―
|
|
2
|
|
5
|
|
|
Net other comprehensive income (loss)
|
|
10
|
|
3
|
|
―
|
|
(14)
|
|
(1)
|
|
|
Balance as of March 31, 2013
|
$
|
(230)
|
$
|
(99)
|
$
|
1
|
$
|
(49)
|
$
|
(377)
|
|
|
(1)
|
All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.
|
||||||||||
For the three months ended March 31, 2014 and 2013, Other Comprehensive Income, excluding amounts attributable to noncontrolling interests, at SDG&E and SoCalGas was negligible, and reclassifications out of Accumulated Other Comprehensive Income (Loss) to Net Income were also negligible for SoCalGas.
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
The following two tables provide a reconciliation of changes in Sempra Energy’s and SDG&E’s shareholders’ equity and noncontrolling interests for the three months ended March 31, 2014 and 2013. The only change in SoCalGas’ shareholders’ equity for the three months ended March 31, 2014 and 2013 was comprehensive income.
|
SHAREHOLDERS’ EQUITY
AND NONCONTROLLING INTERESTS ― SEMPRA ENERGY CONSOLIDATED
|
|||||||
|
(Dollars in millions)
|
|||||||
|
|
|
|
Sempra
|
|
|
|
|
|
|
|
|
Energy
|
|
Non-
|
|
|
|
|
|
|
Shareholders’
|
|
controlling
|
|
Total
|
|
|
|
|
Equity
|
|
Interests
|
|
Equity
|
|
Balance at December 31, 2013
|
$
|
11,008
|
$
|
842
|
$
|
11,850
|
|
|
Comprehensive income
|
|
202
|
|
17
|
|
219
|
|
|
Share-based compensation expense
|
|
10
|
|
―
|
|
10
|
|
|
Common stock dividends declared
|
|
(162)
|
|
―
|
|
(162)
|
|
|
Issuance of common stock
|
|
11
|
|
―
|
|
11
|
|
|
Repurchase of common stock
|
|
(37)
|
|
―
|
|
(37)
|
|
|
Tax benefit related to share-based compensation
|
|
8
|
|
―
|
|
8
|
|
|
Equity contributed by noncontrolling interest
|
|
―
|
|
1
|
|
1
|
|
|
Distributions to noncontrolling interests
|
|
―
|
|
(11)
|
|
(11)
|
|
|
Balance at March 31, 2014
|
$
|
11,040
|
$
|
849
|
$
|
11,889
|
|
|
Balance at December 31, 2012
|
$
|
10,282
|
$
|
401
|
$
|
10,683
|
|
|
Comprehensive income (loss)
|
|
179
|
|
(3)
|
|
176
|
|
|
Preferred dividends of subsidiaries
|
|
(2)
|
|
―
|
|
(2)
|
|
|
Share-based compensation expense
|
|
10
|
|
―
|
|
10
|
|
|
Common stock dividends declared
|
|
(153)
|
|
―
|
|
(153)
|
|
|
Issuance of common stock
|
|
15
|
|
―
|
|
15
|
|
|
Repurchase of common stock
|
|
(45)
|
|
―
|
|
(45)
|
|
|
Tax benefit related to share-based compensation
|
|
2
|
|
―
|
|
2
|
|
|
Sale of noncontrolling interests, net of offering costs
|
|
135
|
|
439
|
|
574
|
|
|
Equity contributed by noncontrolling interest
|
|
―
|
|
4
|
|
4
|
|
|
Distributions to noncontrolling interests
|
|
―
|
|
(3)
|
|
(3)
|
|
|
Balance at March 31, 2013
|
$
|
10,423
|
$
|
838
|
$
|
11,261
|
|
|
SHAREHOLDER’S EQUITY AND
NONCONTROLLING INTEREST ― SDG&E
|
||||||
|
(Dollars in millions)
|
||||||
|
|
|
SDG&E
|
|
Non-
|
|
|
|
|
|
Shareholder’s
|
|
controlling
|
|
Total
|
|
|
|
Equity
|
|
Interest
|
|
Equity
|
|
Balance at December 31, 2013
|
$
|
4,628
|
$
|
91
|
$
|
4,719
|
|
Comprehensive income
|
|
99
|
|
2
|
|
101
|
|
Distributions to noncontrolling interest
|
|
―
|
|
(6)
|
|
(6)
|
|
Balance at March 31, 2014
|
$
|
4,727
|
$
|
87
|
$
|
4,814
|
|
Balance at December 31, 2012
|
$
|
4,222
|
$
|
76
|
$
|
4,298
|
|
Comprehensive income (loss)
|
|
92
|
|
(8)
|
|
84
|
|
Preferred stock dividends declared
|
|
(1)
|
|
―
|
|
(1)
|
|
Equity contributed by noncontrolling interest
|
|
―
|
|
4
|
|
4
|
|
Balance at March 31, 2013
|
$
|
4,313
|
$
|
72
|
$
|
4,385
|
Ownership interests that are held by owners other than Sempra Energy and SDG&E in subsidiaries or entities consolidated by them are accounted for and reported as noncontrolling interests. As a result, noncontrolling interests are reported as a separate component of equity on the Condensed Consolidated Balance Sheets. Earnings or losses attributable to noncontrolling interests are separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income or loss attributable to noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income.
Sale of Noncontrolling Interests
In the first quarter of 2013, a Sempra Energy subsidiary IEnova, completed a private offering in the U.S. and outside of Mexico and a concurrent public offering in Mexico of common stock. The aggregate shares of common stock sold in the offerings represent approximately 18.9 percent of IEnova’s outstanding ownership interest. IEnova is reported within the Sempra Mexico reportable segment.
The proceeds from the offerings, net of offering costs, were approximately $574 million in U.S. dollars or 7.1 billion Mexican pesos. IEnova is using the net proceeds of the offerings primarily for general corporate purposes, and for the funding of its current investments and ongoing expansion plans. Consistent with applicable accounting guidance, changes in noncontrolling interests that do not result in a change of control are accounted for as equity transactions. When there are changes in noncontrolling interests of a subsidiary that do not result in a change of control, any difference between carrying value and fair value related to the change in ownership is recorded as an adjustment to shareholders’ equity. As a result of the offerings and overallotment options, we recorded an increase in Sempra Energy’s shareholders’ equity of $135 million in the first quarter of 2013 for the sale of IEnova shares to noncontrolling interests.
IEnova is a separate legal entity comprised primarily of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA.
We discuss the IEnova offerings in more detail in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Preferred Stock
The preferred stock of SoCalGas is presented at Sempra Energy as a noncontrolling interest. In 2013, SDG&E had preferred stock outstanding until it was fully redeemed in October 2013. At Sempra Energy, the preferred stock dividends of both SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.
At March 31, 2014 and December 31, 2013, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets:
|
OTHER NONCONTROLLING INTERESTS
|
|||||||
|
(Dollars in millions)
|
|
|
|||||
|
|
|
Percent Ownership Held by Others
|
|
|
March 31, 2014
|
|
December 31, 2013
|
|
SDG&E:
|
|
|
|
|
|
|
|
|
Otay Mesa VIE
|
100
|
%
|
$
|
87
|
$
|
91
|
|
|
Sempra South American Utilities:
|
|
|
|
|
|
|
|
|
Chilquinta Energía subsidiaries(1)
|
24.4 – 43.4
|
|
|
26
|
|
27
|
|
|
Luz del Sur
|
20.2
|
|
|
222
|
|
222
|
|
|
Tecsur
|
9.8
|
|
|
4
|
|
3
|
|
|
Sempra Mexico:
|
|
|
|
|
|
|
|
|
IEnova
|
18.9
|
|
|
452
|
|
442
|
|
|
Sempra Natural Gas:
|
|
|
|
|
|
|
|
|
Bay Gas Storage, Ltd.
|
9.1
|
|
|
22
|
|
22
|
|
|
Liberty Gas Storage, LLC
|
25.0
|
|
|
15
|
|
14
|
|
|
Southern Gas Transmission Company
|
49.0
|
|
|
1
|
|
1
|
|
|
Total Sempra Energy
|
|
|
$
|
829
|
$
|
822
|
|
|
(1)
|
Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages amongst these subsidiaries.
|
||||||
TRANSACTIONS WITH AFFILIATES
Loans to and Receivables from Unconsolidated Affiliates – Sempra Energy Consolidated
Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A., an affiliate of Chilquinta Energía that we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. At March 31, 2014, the loan has a $31 million principal balance outstanding plus a negligible amount of accumulated interest at a fixed interest rate of 4 percent.
At March 31, 2014 and December 31, 2013, Sempra Energy had $2 million and $4 million, respectively, in accounts receivable from various Sempra Renewables joint venture investments.
Service Agreements
Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:
Revenues from unconsolidated affiliates at SDG&E and SoCalGas are as follows:
|
REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
|
||||
|
(Dollars in millions)
|
||||
|
|
Three months ended March 31,
|
|||
|
|
2014
|
2013
|
||
|
SDG&E
|
$
|
3
|
$
|
2
|
|
SoCalGas
|
|
18
|
|
15
|
OTHER INCOME, NET
Other Income, Net on the Condensed Consolidated Statements of Operations consists of the following:
INCOME TAXES
|
INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
|
|||||||||||
|
(Dollars in millions)
|
|||||||||||
|
|
|
|
Three months ended March 31,
|
||||||||
|
|
|
2014
|
|
2013
|
|||||||
|
|
|
|
|
|
Effective
|
|
|
|
|
Effective
|
|
|
|
|
|
Income Tax
|
|
Income
|
|
|
Income Tax
|
|
Income
|
|
|
|
|
|
Expense
|
|
Tax Rate
|
|
|
Expense
|
|
Tax Rate
|
|
|
Sempra Energy Consolidated
|
$
|
127
|
|
33
|
%
|
$
|
178
|
|
51
|
%
|
|
|
SDG&E
|
|
83
|
|
45
|
|
|
51
|
|
39
|
|
|
|
SoCalGas
|
|
38
|
|
33
|
|
|
24
|
|
34
|
|
|
Changes in Income Tax Expense and Effective Income Tax Rates
Sempra Energy Consolidated
The decrease in income tax expense in the three months ended March 31, 2014 was due to a lower effective tax rate offset by higher pretax income. The change in the effective income tax rate was primarily due to:
|
§
|
$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings above in “Shareholders’ Equity and Noncontrolling Interests – Sale of Noncontrolling Interests;”
offset by
|
|
§
|
a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in the San Onofre Nuclear Generating Station (SONGS) that management believes may no longer be recoverable from customers in rates pursuant to the proposed settlement agreement to resolve the California Public Utilities Commission’s (CPUC) Order Instituting Investigation (OII) into the SONGS outage that we discuss in Note 9; and
|
|
§
|
$12 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru.
|
Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted are factored into the forecasted effective tax rate and their impact is recognized proportionately over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software expenditures, repairs to certain utility plant fixed assets, renewable energy income tax credits, deferred income tax benefits related to renewable energy projects, exclusions from taxable income of the equity portion of AFUDC, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, Mexican currency translation and inflation adjustments, and deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.
SDG&E
The increase in SDG&E’s income tax expense in the three months ended March 31, 2014 was primarily due to a higher effective tax rate and also to higher pretax income. The higher effective tax rate was primarily due to the $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS discussed in Note 9.
The results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is not included in Sempra Energy’s federal or state income tax returns but is consolidated for financial statement purposes, and therefore, Sempra Energy Consolidated’s and SDG&E’s effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate. We discuss Otay Mesa VIE above in “Variable Interest Entities.”
SoCalGas
The increase in SoCalGas’ income tax expense in the three months ended March 31, 2014 was primarily due to higher pretax income offset by higher deductions for certain repairs expenditures that are capitalized for financial statement purposes.
The CPUC requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment:
|
§
|
repairs expenditures related to a certain portion of utility plant fixed assets
|
|
§
|
the equity portion of AFUDC
|
|
§
|
a portion of the cost of removal of utility plant assets
|
|
§
|
self-developed software expenditures
|
|
§
|
depreciation on a certain portion of utility plant fixed assets
|
The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.
We provide additional information about our accounting for income taxes in Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report.
COMMITTED LINES OF CREDIT
At March 31, 2014, Sempra Energy Consolidated had an aggregate of $4.1 billion in committed lines of credit to provide liquidity and to support commercial paper, the major components of which we detail below. Available unused credit on these lines at March 31, 2014 was $2.7 billion.
Sempra Energy
Sempra Energy has a $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share.
Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At March 31, 2014 and December 31, 2013, Sempra Energy was in compliance with this and all other financial covenants under the credit facility. The facility also provides for issuance of up to $635 million of letters of credit on behalf of Sempra Energy with the amount of borrowings otherwise available under the facility reduced by the amount of outstanding letters of credit.
At March 31, 2014, Sempra Energy had $6 million of letters of credit outstanding supported by the facility.
Sempra Global
Sempra Global has a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share.
Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At March 31, 2014 and December 31, 2013, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.
At March 31, 2014, Sempra Global had $1.3 billion of commercial paper outstanding supported by the facility. At March 31, 2014, and December 31, 2013, Sempra Global had $300 million and $200 million, respectively, of commercial paper outstanding classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows.
California Utilities
SDG&E and SoCalGas have a combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $300 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit.
Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility’s credit ratings. The agreement requires each utility to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At March 31, 2014 and December 31, 2013, the California Utilities were in compliance with this and all other financial covenants under the credit facility.
Each utility’s obligations under the agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility.
At March 31, 2014, SDG&E had $90 million outstanding borrowings supported by the facility. SoCalGas had no outstanding borrowings supported by the facility. Available unused credit on the line at March 31, 2014 was $568 million at SDG&E and $658 million at SoCalGas, subject to the combined limit on the facility of $877 million.
WEIGHTED AVERAGE INTEREST RATES
The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.65 percent and 0.64 percent at March 31, 2014 and December 31, 2013, respectively. The weighted average interest rate on total short-term debt outstanding at SDG&E was 0.13 percent at March 31, 2014, and 0.13 percent at both SDG&E and SoCalGas at December 31, 2013. The weighted average interest rate at Sempra Energy at December 31, 2013 includes interest rates for commercial paper borrowings classified as long-term, as we discuss above.
LONG-TERM DEBT
SoCalGas
In March 2014, SoCalGas publicly offered and sold $250 million of 4.45-percent first mortgage bonds maturing in 2044. SoCalGas used the proceeds from this offering for the repayment of its 5.5-percent first mortgage bonds that were due in March 2014.
Sempra Renewables
On March 6, 2014, Sempra Renewables entered into a $356 million construction loan to finance its Copper Mountain Solar 3 project. The loan is secured by the project and will convert to a 10-year term loan upon completion of the project. To partially moderate its exposure to interest rate changes, Copper Mountain Solar 3 entered into floating-to-fixed interest rate swaps for 75 percent of the loan amount, resulting in an effective fixed rate of 5.35 percent. The remaining 25 percent bears interest at rates varying with market rates (0.15 percent at March 31, 2014). In connection with the loan agreement, Copper Mountain Solar 3 may also utilize up to $72 million under a letter of credit facility, which may be used to meet project collateral requirements and debt service reserve requirements. On March 6, 2014, Sempra Renewables drew down $97 million from the loan. On March 13, 2014, this $97 million of long-term debt and related swaps were deconsolidated upon the sale of a 50-percent interest in Copper Mountain Solar 3, as we discuss in Note 3.
INTEREST RATE SWAPS
We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.
We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not presented below.
We record all derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows.
In certain cases, we apply the normal purchase or sale exception to derivative accounting and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.
HEDGE ACCOUNTING
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that a given future revenue or expense item may vary, and other criteria.
We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.
ENERGY DERIVATIVES
Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business.
|
§
|
The California Utilities use natural gas energy derivatives, on their customers’ behalf, with the objective of managing price risk and basis risks, and lowering natural gas costs. These derivatives include fixed price natural gas positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.
|
|
§
|
SDG&E is allocated and may purchase congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations.
|
|
§
|
Sempra Mexico and Sempra Natural Gas may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (LNG), natural gas transportation, power generation, and Sempra Natural Gas’ storage. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.
|
|
§
|
From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel.
|
We summarize net energy derivative volumes at March 31, 2014 and December 31, 2013 as follows:
In addition to the amounts noted above, we frequently use commodity derivatives to manage risks associated with the physical locations of our assets and other contractual obligations, such as natural gas purchases and sales.
INTEREST RATE DERIVATIVES
We are exposed to interest rates primarily as a result of our current and expected use of financing. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.
In the first quarter of 2014, we entered into three tranches of interest rate swaps to hedge the risk of the overall change in fair value of $500 million of Sempra Energy’s fixed price debt. The first tranche hedges the fair value of $200 million of Sempra Energy’s $500 million 6.15-percent fixed-rate debt outstanding, maturing in 2018, resulting in an effective interest rate of 3.80-percent. The second tranche hedges $200 million of Sempra Energy’s $500 million 9.8-percent fixed-rate debt outstanding, maturing in 2019, resulting in an effective interest rate of 6.01-percent. The last tranche hedges the fair value of $100 million of Sempra Energy’s $500 million 2.875-percent fixed-rate debt outstanding, maturing in 2022, resulting in an effective interest rate of 2.37-percent.
Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries. Although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to natural gas derivatives. Accordingly, interest rate derivatives are generally accounted for as hedges at the California Utilities, as well as at the rest of Sempra Energy’s subsidiaries. Separately, Otay Mesa VIE has entered into interest rate swap agreements to moderate its exposure to interest rate changes. This activity was designated as a cash flow hedge as of April 1, 2011.
At March 31, 2014 and December 31, 2013, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:
|
INTEREST RATE DERIVATIVES
|
|||||||
|
(Dollars in millions)
|
|||||||
|
|
|
March 31, 2014
|
December 31, 2013
|
||||
|
|
Notional Debt
|
Maturities
|
Notional Debt
|
Maturities
|
|||
|
Sempra Energy Consolidated:
|
|
|
|
|
|
|
|
|
Cash flow hedges(1)
|
$
|
411
|
2014-2028
|
$
|
413
|
2014-2028
|
|
|
Fair value hedges
|
|
800
|
2016-2022
|
|
300
|
2016
|
|
|
SDG&E:
|
|
|
|
|
|
|
|
|
Cash flow hedge(1)
|
|
332
|
2019
|
|
335
|
2019
|
|
|
(1)
|
Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.
|
||||||
FOREIGN CURRENCY DERIVATIVES
We are exposed to exchange rate movements at our Mexican subsidiaries, which have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts. We may also utilize cross-currency swaps to hedge exposure related to Mexican peso-denominated debt at our Mexican subsidiaries. On February 14, 2013, Sempra Mexico entered into cross-currency swap agreements, which were designated as cash flow hedges. We discuss the notional amount of the swaps in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
In addition, Sempra South American Utilities may utilize foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk. We discuss such swaps at Chilquinta Energía’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
FINANCIAL STATEMENT PRESENTATION
Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions and cash collateral with the same counterparty when management believes a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.
The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and in Other Comprehensive Income (OCI) and Accumulated Other Comprehensive Income (AOCI) for the three months ended March 31 were:
|
CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
|||||||||||
|
(Dollars in millions)
|
|||||||||||
|
|
|
Pretax gain (loss) recognized
|
|
|
Loss reclassified from AOCI
|
||||||
|
|
|
in OCI (effective portion)
|
|
|
into earnings (effective portion)
|
||||||
|
|
|
Three months ended March 31,
|
|
|
Three months ended March 31,
|
||||||
|
|
2014
|
2013
|
|
Location
|
2014
|
2013
|
|||||
|
Sempra Energy Consolidated:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate and foreign
|
|
|
|
|
|
|
|
|
|
|
|
|
exchange instruments(1)
|
$
|
(3)
|
$
|
(28)
|
|
Interest Expense
|
$
|
(3)
|
$
|
(3)
|
|
|
|
|
|
|
|
|
|
Gain on Sale of Equity
|
|
|
|
|
|
Interest rate instruments
|
|
(2)
|
|
―
|
|
Interest and Assets
|
|
(2)
|
|
―
|
|
|
|
|
|
|
|
|
Equity Earnings,
|
|
|
|
|
|
|
Interest rate instruments
|
|
(15)
|
|
1
|
|
Before Income Tax
|
|
(3)
|
|
(2)
|
|
|
Commodity contracts not subject
|
|
|
|
|
|
Cost of Natural Gas, Electric
|
|
|
|
|
|
|
to rate recovery
|
|
(6)
|
|
―
|
|
Fuel and Purchased Power
|
|
(10)
|
|
―
|
|
|
Total(2)
|
$
|
(26)
|
$
|
(27)
|
|
|
$
|
(18)
|
$
|
(5)
|
|
|
SDG&E:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate instruments(1)(2)
|
$
|
(3)
|
$
|
1
|
|
Interest Expense
|
$
|
(3)
|
$
|
(2)
|
|
|
(1)
|
Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
|
||||||||||
|
(2)
|
There was a negligible amount of ineffectiveness related to these swaps in 2014 and 2013.
|
||||||||||
For Sempra Energy Consolidated we expect that losses of $24 million, which are net of income tax benefit, that are currently recorded in AOCI (including $12 million in noncontrolling interests, of which $11 million is related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.
SoCalGas expects negligible losses, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.
For all forecasted transactions, the maximum term over which we are hedging exposure to the variability of cash flows at March 31, 2014 is approximately 15 years and 5 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables’ equity method investees is 21 years.
The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months ended March 31 were:
|
UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
|
||||||
|
(Dollars in millions)
|
||||||
|
|
|
|
Gain (loss) on derivatives recognized in earnings
|
|||
|
|
|
|
Three months ended March 31,
|
|||
|
|
Location
|
2014
|
2013
|
|||
|
Sempra Energy Consolidated:
|
|
|
|
|
|
|
|
Interest rate and foreign exchange
|
|
|
|
|
|
|
|
instruments
|
Other Income, Net
|
$
|
―
|
$
|
7
|
|
|
Foreign exchange instruments
|
Equity Earnings,
|
|
|
|
|
|
|
|
|
Net of Income Tax
|
|
(2)
|
|
―
|
|
Commodity contracts not subject
|
Revenues: Energy-Related
|
|
|
|
|
|
|
to rate recovery
|
Businesses
|
|
(5)
|
|
(20)
|
|
|
Commodity contracts subject
|
Cost of Electric Fuel
|
|
|
|
|
|
|
to rate recovery
|
and Purchased Power
|
|
12
|
|
9
|
|
|
Commodity contracts subject
|
|
|
|
|
|
|
|
to rate recovery
|
Cost of Natural Gas
|
|
2
|
|
―
|
|
|
Total
|
|
$
|
7
|
$
|
(4)
|
|
|
SDG&E:
|
|
|
|
|
|
|
|
Commodity contracts subject
|
Cost of Electric Fuel
|
|
|
|
|
|
|
to rate recovery
|
and Purchased Power
|
$
|
12
|
$
|
9
|
|
|
SoCalGas:
|
|
|
|
|
|
|
|
Commodity contracts subject
|
|
|
|
|
|
|
|
to rate recovery
|
Cost of Natural Gas
|
$
|
2
|
$
|
―
|
|
CONTINGENT FEATURES
For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending upon our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization.
For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position at March 31, 2014 and December 31, 2013 is $1 million and $3 million, respectively. At March 31, 2014, if the credit ratings of Sempra Energy were reduced below investment grade, $1 million of additional assets could be required to be posted as collateral for these derivative contracts.
For SDG&E, the total fair value of this group of derivative instruments in a net liability position was negligible at March 31, 2014 and $3 million at December 31, 2013. At March 31, 2014, if the credit ratings of SDG&E were reduced below investment grade, a negligible amount of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra Energy Consolidated, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.
We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the three months ended March 31, 2014.
Recurring Fair Value Measures
The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 2014 and December 31, 2013. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our 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.
The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 under “Financial Statement Presentation.”
The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).
Our financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 2014 and December 31, 2013 in the tables below include the following:
|
§
|
Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
|
|
§
|
We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. We may also manage foreign exchange rate exposures using derivatives. We primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). All Level 3 recurring items are related to CRRs at SDG&E, as we discuss below under “Level 3 Information.” We record commodity derivative contracts that are subject to rate recovery as commodity costs that are offset by regulatory account balances and are recovered in rates.
|
|
§
|
Investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1).
|
There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented, nor any changes in valuation techniques used in recurring fair value measurements.
Level 3 Information
The following table sets forth reconciliations of changes in the fair value of Congestion Revenue Rights (CRRs) classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:
|
LEVEL 3 RECONCILIATIONS
|
||||
|
(Dollars in millions)
|
||||
|
|
Three months ended March 31,
|
|||
|
|
2014
|
2013
|
||
|
Balance at January 1
|
$
|
99
|
$
|
61
|
|
Realized and unrealized gains (losses)
|
|
1
|
|
(1)
|
|
Allocated transmission instruments
|
|
1
|
|
―
|
|
Settlements
|
|
(6)
|
|
(2)
|
|
Balance at March 31
|
$
|
95
|
$
|
58
|
|
Change in unrealized gains or losses relating to
|
|
|
|
|
|
instruments still held at March 31
|
$
|
―
|
$
|
―
|
SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs on an ongoing basis. Inputs used to determine the fair value of CRRs are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to CRRs to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.
CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (CAISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. At March 31, 2014 the auction prices ranged from $(6) per MWh to $12 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. At March 31, 2013 the auction prices ranged from $(11) per MWh to $12 per MWh. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.
Fair Value of Financial Instruments
The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments at March 31, 2014 and December 31, 2013:
We base the fair value of certain long-term debt and preferred stock on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).
We provide the fair values for the securities held in the nuclear decommissioning trust funds related to SONGS in Note 9 below.
SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California, which ceased operations in June 2013. On June 6, 2013, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified SDG&E that it had reached a decision to permanently retire SONGS and seek approval from the Nuclear Regulatory Commission (NRC) to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdiction of the NRC and the CPUC.
SDG&E, and each of the other owners, holds its undivided interest as a tenant in common in the property. Each owner is responsible for financing its share of expenses and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations.
SONGS Outage and Retirement
Background
As part of the Steam Generator Replacement Project (SGRP), the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Edison concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generators as well. In March 2012, in response to the shutdown of SONGS, the NRC issued a Confirmatory Action Letter (CAL) which, among other things, outlined the requirements for Edison to meet before the NRC would approve a restart of either of the Units.
In October 2012, Edison submitted a restart plan to the NRC proposing to operate Unit 2 at a reduced power level for a period of five months, at which time the Unit would be brought down for further inspection. Edison did not file a restart plan for Unit 3, pending further inspection and analysis of what repairs or modifications would be required to return the Unit to service in a safe manner. The NRC was reviewing the restart plan for Unit 2 proposed by Edison when in May 2013, the Atomic Safety and Licensing Board (ASLB), an adjudicatory arm of the NRC, concluded that the CAL process constituted a de facto license amendment proceeding that was subject to a public hearing. This conclusion by the ASLB resulted in further uncertainty regarding when a final decision might be made on restarting Unit 2.
The steam generators were designed and provided by Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted arbitration proceedings against MHI seeking damages as well. We discuss these proceedings in Note 11.
Proposed Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII)
SONGS OII
In November 2012, in response to the outage, the CPUC issued the SONGS OII, pursuant to California Public Utilities’ Code Section 455.5, which applies to cost recovery issues resulting from long-term outages of operating assets. The SONGS OII consolidated most SONGS outage-related issues into a single proceeding. The SONGS OII, among other things, designated all revenues associated with the investment in, and operation of, SONGS since January 1, 2012 as subject to refund to customers, pending the outcome of all phases of the proceeding. The SONGS OII proceeding is also intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA) subject only to a reasonableness review by the CPUC. We provide additional information on the SONGS OII in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Entry Into Settlement Agreement
Pursuant to CPUC rules concerning settlements, SDG&E, Edison, The Utility Reform Network (TURN), and the CPUC Office of Ratepayer Advocates (ORA) gave advance written notice to all parties in the SONGS OII of a conference to discuss the terms to resolve the SONGS OII. The settlement conference was held on March 27, 2014. On April 3, 2014, SDG&E, along with Edison, TURN, ORA and two other intervenors to the SONGS OII proceeding, filed a Settlement Agreement with the CPUC. If approved by the CPUC, the Settlement Agreement will constitute a complete and final resolution of the SONGS OII and related CPUC proceedings regarding the SGRP at SONGS and the related outage and subsequent shutdown of SONGS. The Settlement Agreement does not affect on-going or future proceedings before the NRC, or litigation or arbitration related to potential future recoveries from third parties or proceedings addressing decommissioning activities and costs.
Implementation of the terms of the Settlement Agreement is subject to the approval of the CPUC, as to which there is no assurance. The parties to the Settlement Agreement (Settling Parties) have agreed to exercise their best efforts to obtain CPUC approval. The Settlement Agreement is subject to termination by any of the Settling Parties if the CPUC has not approved it within six months of submission to the CPUC. There is no assurance that the CPUC will approve the Settlement Agreement, or when or what the CPUC will actually decide.
The following is a summary of the Settlement Agreement.
Disallowances, Refunds and Rate Recoveries
If the Settlement Agreement is approved as filed with the CPUC, SDG&E will
|
§
|
remove from rate base, as of February 1, 2012, its investment in the SGRP and refund to its customers the amount collected for its investment in and any return on its investment in the SGRP since such date. As of February 1, 2012, SDG&E’s net book value in the SGRP was approximately $160 million;
|
|
§
|
be authorized to recover in rates its remaining investment in SONGS, including base plant and construction work in progress (CWIP), generally over a ten-year period commencing February 1, 2012, together with a return on investment at a reduced rate equal to:
|
|
□
|
SDG&E’s weighted average return on debt, plus
|
|
□
|
50 percent of SDG&E’s weighted average return on preferred stock, as authorized in the CPUC’s Cost of Capital proceeding then in effect (collectively, SONGS ROR).
|
This results in a SONGS ROR of 2.75 percent for the period February 1, 2012 through December 31, 2012 and 2.35 percent for the period January 1, 2013 through December 31, 2014. The SONGS ROR for future periods will fluctuate based on SDG&E’s authorized weighted average returns on debt and preferred stock in effect for those future periods;
|
§
|
be authorized to recover in rates its recorded operations and maintenance expenses for 2012, 2013 and 2014 as well as the recorded costs for the 2012 refueling outage of Unit 2, subject to customary prudency review;
|
|
§
|
be authorized to recover in rates its remaining investment in materials and supplies over a ten-year period commencing February 1, 2012, together with a return on investment at the SONGS ROR;
|
|
§
|
be authorized to recover in rates its remaining investment in nuclear fuel inventory and any costs incurred, or to be incurred, associated with nuclear fuel supply contracts over a ten-year period, together with a return equal to SDG&E’s commercial paper borrowing rate; and
|
|
§
|
be authorized to recover in rates through its fuel and purchased power balancing account (ERRA) all costs incurred to purchase power in the market to replace the power that would have been generated at SONGS if not for the outage and shutdown of SONGS, and to recover by December 31, 2015 any SONGS-related ERRA undercollections. SDG&E’s market power costs through June 6, 2013 (the date of SONGS’ retirement) were approximately $165 million, using the methodology followed in the SONGS OII (and approximately $79 million of additional costs incurred for the period June 7 through December 31, 2013).
|
The Settlement Agreement also provides SDG&E with an incentive in the event proceeds are secured from the sale of materials and supplies and/or nuclear fuel, as well as in the event that nuclear fuel investments are reduced by contract cancellations. This incentive allows SDG&E to retain 5 percent of its proportionate share of any sales proceeds and to recover 5 percent of its proportionate share of the excess of cancelled contract obligations over cancellation costs. The balance of the sale proceeds and cancellation benefits is credited to ratepayers.
Potential Third Party Recoveries
The Settlement Agreement also addresses how potential recoveries from third parties will be allocated between ratepayers and SDG&E.
As we discuss in Note 11, SDG&E and the other owners of SONGS carry accidental property damage and accidental outage insurance issued by Nuclear Electric Insurance Limited (NEIL), a mutual insurance company. Edison, on behalf of itself and the other minority owners in SONGS (including SDG&E), has placed NEIL on notice of claims under both policies. Under the Settlement Agreement, recoveries from NEIL, if any, will first be applied to reimburse costs incurred in pursuing such recoveries, including litigation costs. To the extent SDG&E’s share of recoveries from NEIL exceeds such costs, recoveries will be allocated 82.5 percent to ratepayers and 17.5 percent to SDG&E.
As we discuss in Note 11, SDG&E has filed a lawsuit against MHI, which designed and provided the steam generators that failed. This proceeding was stayed in favor of an arbitration proceeding instituted by Edison. Under the Settlement Agreement, recoveries from MHI, if any, will first be applied to reimburse costs incurred in pursuing such recoveries, including litigation costs. We provide additional information on the proceedings against MHI in Note 11.
To the extent SDG&E’s share of recoveries from MHI exceeds such costs, they will be allocated as follows:
|
§
|
85 percent of the first $25 million to SDG&E, and 15 percent to ratepayers;
|
|
§
|
66.67 percent of the next $200 million to SDG&E, and 33.33 percent to ratepayers; and
|
|
§
|
25 percent of any additional recoveries to SDG&E, and 75 percent to ratepayers.
|
The Settlement Agreement provides for the resolution of the claims with NEIL and the dispute with MHI without requiring CPUC review or approval, but requires that Edison and SDG&E use their best efforts to inform the CPUC of any settlements or resolutions of the issues to the extent possible without compromising any aspect of such settlements or resolutions.
There is no assurance that there will be any recoveries from NEIL or MHI or that if there are recoveries, that they will exceed the costs incurred to pursue them. Were there to be recoveries, SDG&E cannot provide any assurance as to when they would be received or the amount of any such recoveries. SDG&E currently expects that NEIL will make a coverage determination by the end of the second quarter of 2014.
Accounting and Financial Impacts
As a result of the execution of the Settlement Agreement by the Settling Parties, SDG&E has now concluded that the probable outcome of the SONGS OII is the approval and implementation of the Settlement Agreement, although such outcome is dependent on approval by the CPUC.
As disclosed in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report, SDG&E reported a pretax loss from plant closure of $200 million ($119 million after-tax) in the second quarter of 2013 as a result of its initial assessment of the financial impact of the outcome of the SONGS OII proceeding. As a result of entering into the Settlement Agreement in the first quarter of 2014, SDG&E recorded a $13 million reduction to the pretax loss from plant closure, but a $9 million increase in the after-tax loss from plant closure. The after-tax loss includes a $17 million charge to reduce certain tax regulatory assets, as we discuss in Note 5. After adjustment for the Settlement Agreement, the total loss from plant closure, including amounts previously recorded in 2013, is $187 million pretax ($128 million after-tax). A regulatory asset for the expected recovery of SONGS costs, consistent with the Settlement Agreement, is recorded on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E in Other Regulatory Assets (long-term). The amount of this regulatory asset is $255 million as of March 31, 2014.
Assuming the Settlement Agreement is approved, and except for the impact of the amount and timing of any potential future recoveries from third parties, which SDG&E cannot estimate at this time, SDG&E does not expect that implementation of the Settlement Agreement will have a material adverse impact on its future results of operations or financial condition.
Procedure
Under the Settlement Agreement, the Settling Parties are required to use their best efforts to obtain CPUC approval. In April 2014, the Settling Parties filed a Motion requesting the CPUC to:
|
§
|
approve the Settlement Agreement without change;
|
|
§
|
find the Settlement Agreement reasonable;
|
|
§
|
withdraw the November 19, 2013 Proposed Decision on Phase 1 and Phase 1A issues in the SONGS OII; and
|
|
§
|
expedite consideration of the Settlement Agreement in order to provide its benefits to ratepayers as soon as possible.
|
During the pendency of proceedings regarding the Settlement Agreement, the Settling Parties are further bound to:
|
§
|
support and mutually defend the Settlement Agreement in its entirety;
|
|
§
|
oppose any modifications proposed by any non-settling party to the SONGS OII unless all Settling Parties agree; and
|
|
§
|
cooperate reasonably on all submissions necessary to achieve CPUC approval.
|
The Settling Parties further agree to review any CPUC orders regarding the Settlement Agreement to determine if the CPUC has changed or modified it, deleted a term or imposed a new term. If any Settling Party is unwilling to accept any such change, modification, deletion or addition of a new term, then the Settling Parties will negotiate in good faith to seek a resolution acceptable to all Settling Parties. If they are unable to resolve the matter to the satisfaction of all Settling Parties, or to obtain prompt CPUC approval of an agreed upon resolution, then any Settling Party can terminate the Settlement Agreement upon prompt notice.
Under CPUC rules, parties to the SONGS OII will have an opportunity to comment on the Motion and Settlement Agreement, and if there are objections raising factual issues, then the CPUC’s review may include evidentiary proceedings. On April 15, 2014, the Administrative Law Judge (ALJ) assigned to the SONGS OII proceeding issued the following preliminary schedule regarding the proposed settlement:
|
§
|
An evidentiary hearing will be held to evaluate the proposed Settlement Agreement and relevant facts on or about May 14, 2014.
|
|
§
|
The due date for reply comments on the motion to adopt the proposed Settlement Agreement shall be deferred until after the evidentiary hearing, to on or about May 22, 2014.
|
|
§
|
The Settling Parties shall host a community meeting on or about June 16, 2014 to present the proposed settlement to the public.
|
Pursuant to the CPUC’s rules, no settlement becomes binding unless the CPUC approves the settlement based on a finding that it is reasonable in light of the whole record, consistent with law, and in the public interest. The CPUC has discretion to approve or disapprove a settlement, or to condition its approval on changes to the settlement, which the parties may accept or reject. CPUC rules do not provide for any fixed time period for the CPUC to act on the Settlement Agreement.
Unless and until the CPUC approves the Settlement Agreement as filed, there can be no assurance that the SONGS OII proceeding will provide for recoveries as currently estimated by SDG&E in accordance with the Settlement Agreement, including the recovery of costs recorded as a regulatory asset, or that the CPUC will not order refunds to customers above those contemplated by the Settlement Agreement. Therefore, the regulatory asset of $255 million in Other Regulatory Assets on the Condensed Consolidated Balance Sheets of Sempra Energy and SDG&E at March 31, 2014 related to the SONGS plant closure could be subject to further change based upon future developments and the application of SDG&E’s judgment to those events.
NRC Proceedings
In December 2013, Edison received a final NRC Inspection Report that identified a violation for the failure to verify the adequacy of the thermal-hydraulic and flow-induced vibration design of the Unit 3 replacement steam generators. In January 2014, Edison provided a response to the NRC Inspection Report stating that MHI, as contracted by Edison to prepare the SONGS replacement steam generator design, was the party responsible for validating the design of the steam generators.
In addition, the NRC issued an Inspection Report to MHI containing a Notice of Nonconformance for its flawed computer modeling in the design of the replacement steam generators.
Because SONGS has ceased operation, NRC inspection oversight of SONGS will now be continued through the NRC’s Decommissioning Power Reactor Inspection Program to verify that decommissioning activities are being conducted safely, that spent fuel is safely stored onsite or transferred to another licensed location, and that the site operations and licensee termination activities conform to applicable regulatory requirements, licensee commitments and management controls.
Nuclear Decommissioning and Funding
As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begun the decommissioning phase of the plant. The process of decommissioning a nuclear power plant is governed by the regulations of various governmental and other agencies, including but not limited to, those of the NRC, the U.S. Department of the Navy (the land owner) and the CPUC. The NRC regulations generally categorize the decommissioning activities into three phases: initial activities, major decommissioning and storage activities, and license termination. Initial activities include providing notice of permanent cessation of operations (provided by Edison to the NRC on June 12, 2013) and notice of permanent removal of fuel from the reactor vessels (provided by Edison on June 28 and July 22, 2013 for Units 3 and 2, respectively). Within two years after the cessation of operations, the licensee (Edison) must submit a post-shutdown decommissioning activities report, an irradiated fuel management plan and a site-specific decommissioning cost estimate. Edison currently estimates that it will provide these documents to the NRC by the end of 2014.
In accordance with state and federal requirements and regulations, SDG&E has assets held in trusts, referred to as the Nuclear Decommissioning Trusts (NDT), to fund decommissioning costs for SONGS Units 1, 2 and 3. At March 31, 2014, the fair value of SDG&E’s NDT assets was $1.1 billion. Except for the use of funds for the planning of decommissioning activities, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs. In February 2014, SDG&E filed a request with the CPUC for such authorization for costs incurred in 2013. Until CPUC approval to access the NDT to pay for such costs is received, SDG&E will use working capital to pay for any SONGS decommissioning costs incurred, and such expenditures will be reimbursed from the NDT upon that approval. The timing of SDG&E’s access to the NDT assets may also depend on a finding by the NRC that the monies in the SONGS trust funds may be used to pay for each of the three general categories of decommissioning activities. These activities are as follows:
|
§
|
NRC-jurisdictional radiological decommissioning (also known as “license termination”)
|
|
§
|
spent fuel management and decommissioning at an independent spent fuel storage installation
|
|
§
|
non-radiological purposes, i.e., site restoration
|
SDG&E and Edison have a joint application pending with the CPUC requesting continued rate recovery to fund the NDT to ensure that the NDT has sufficient funding to pay for the estimated cost for decommissioning of SONGS. SDG&E is currently authorized to recover $8 million annually to fund additional investments in the NDT to pay for the cost of decommissioning SONGS. In its pending application with the CPUC, SDG&E is requesting to recover $16 million on an annual basis to fund additional investments in the NDT. We expect a decision on this application in the second half of 2014.
Nuclear Decommissioning Trusts
The amounts collected in rates for SONGS’ decommissioning are invested in externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are shown on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.
The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds:
The following table shows the proceeds from sales of securities in the trusts and gross realized gains and losses on those sales:
Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.
We provide additional information about SONGS in Note 11.
We discuss regulatory matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below.
JOINT MATTERS
CPUC General Rate Case (GRC)
The CPUC uses a general rate case proceeding to prospectively set rates sufficient to allow the California Utilities to recover their reasonable cost of operations and maintenance and to provide the opportunity to realize their authorized rates of return on their investment. In May 2013, the CPUC approved a final decision (Final GRC Decision) in the California Utilities’ 2012 GRC. The Final GRC Decision was effective retroactive to January 1, 2012, and SDG&E and SoCalGas recorded the cumulative earnings effect of the retroactive application of the Final GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts include an incremental earnings impact of $52 million and $25 million related to 2012 and $17 million and $12 million related to the first quarter of 2013.
The amount of revenue associated with the retroactive period is expected to be recovered in SDG&E’s rates over a 28-month period beginning in September 2013, and in SoCalGas’ rates over a 31-month period beginning in June 2013. At March 31, 2014, SDG&E reported on its Condensed Consolidated Balance Sheet $284 million as a regulatory asset, with $122 million classified as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered by SDG&E in rates through December 2015. At March 31, 2014, SoCalGas reported on its Condensed Consolidated Balance Sheet a regulatory asset of $91 million, with $39 million as noncurrent, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015.
We provide additional information regarding the 2012 GRC in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
Natural Gas Pipeline Operations Safety Assessments
Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.
In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011.
In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E’s and SoCalGas’ Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies’ PSEP.
In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report on the California Utilities’ PSEP. The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process. Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable.
In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012.
In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.
Also in April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill (SB) 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. The CPUC’s Safety and Enforcement Division will select the independent auditors and will oversee the audits. A schedule for the audits has not been established. In December 2012, the CPUC issued a final decision accepting the utilities’ pipeline safety plans filed pursuant to SB 705.
On April 15, 2014, the assigned ALJ issued a proposed decision in the TCAP proceeding addressing SDG&E’s and SoCalGas’ PSEP filing (PSEP PD). While the PSEP PD is ambiguous in a number of key areas, management has determined that if the PSEP PD is adopted in its current form, it:
|
§
|
approves the utilities’ model for implementing PSEP;
|
|
§
|
approves a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers of interim costs incurred to implement PSEP, which are recorded in the regulatory accounts authorized by the CPUC as noted above;
|
|
§
|
approves balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and
|
|
§
|
establishes the criteria to determine the amounts that would not be eligible for cost recovery, including certain costs incurred or to be incurred associated with records review, the cost of pressure testing pipelines installed after 1955 for which the company has not found sufficient records of testing, and any undepreciated balances for pipelines that were replaced as a result of this program.
|
The utilities are seeking additional clarification on a number of key areas within the proposed decision and plan to file comments with the CPUC by the deadline of May 5, 2014.
Through March 31, 2014, SDG&E and SoCalGas have incurred, and recorded in the CPUC-authorized regulatory account, $2 million and $56 million, respectively, associated with the implementation of their PSEPs.
We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E MATTERS
SONGS
We discuss regulatory and other matters related to SONGS in Note 9.
Power Procurement and Resource Planning
Sycamore-Penasquitos Transmission Project
In March 2014, the CAISO selected SDG&E, as a result of a competitive bid process, to construct the Sycamore-Penasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Penasquitos substations. In April 2014, SDG&E filed an application with the CPUC requesting a Certificate of Public Convenience and Necessity (CPCN) to construct the line. The estimated $120 million to $150 million project was identified by a state task force as necessary to ensure grid reliability given the closure of SONGS. The project will also serve to strengthen renewable energy infrastructure in the region. SDG&E expects a CPUC decision approving the project in the first half of 2016, with the line expected to be in service in mid-2017.
South Orange County Reliability Enhancement
SDG&E filed an application with the CPUC in May 2012 for a CPCN to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E’s electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $400 million to $500 million project in 2015. SDG&E obtained approval for the project from the CAISO in May 2011. As the project is planned in phases, SDG&E currently expects the entire project to be in service in 2019.
South Bay Substation
SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation to replace the aging and obsolete South Bay substation and accommodate the retirement of the South Bay Power Plant. The existing substation will be demolished when the new substation has been constructed, energized and all transmission lines have been transferred. In October 2013, the CPUC approved SDG&E’s permit to construct the South Bay substation at SDG&E’s proposed site. The project, estimated at $145 million to $175 million, will replace the existing 138/69-kV substation with the new 230/69/12-kV Bay Boulevard substation. In March 2014, the California Coastal Commission approved the project, subject to certain additional environmental enhancements. SDG&E is in the process of obtaining the remaining permits required to begin construction. SDG&E currently expects the project to be in service in 2017.
Energy Resource Recovery Account (ERRA)
The ERRA is the regulatory balancing account that SDG&E uses to recover the electric fuel and purchased power costs it incurs to provide energy to its bundled service customers. SDG&E files an application with the CPUC each year to establish the ERRA revenue requirement needed for the following calendar year. Additionally, to the extent the ERRA balance exceeds a certain tolerance or “ERRA Trigger”, SDG&E must file an application to adjust its rates upward or downward, as applicable, to address the under- or over-collected ERRA balance, respectively. In February 2014, the CPUC issued a decision granting SDG&E authority to increase rates to recover an ERRA Trigger revenue requirement of $221 million, which rate increase was effective on April 1, 2014 and will continue through December 31, 2015. In April 2014, the CPUC issued a draft decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $243 million compared to the 2013 ERRA revenue requirement of $987.7 million. SDG&E expects a final CPUC decision in the second quarter of 2014.
Excess Wildfire Claims Cost Recovery
In August 2009, SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC proposing a new framework and mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In December 2012, the CPUC issued a final decision that ultimately did not approve the proposed framework for the utilities but allowed SDG&E to maintain its authorized memorandum account so that SDG&E may file applications with the CPUC requesting recovery of amounts properly recorded in the memorandum account at a later time, subject to reasonableness review.
In February 2014, the Presiding Judge assigned by the Federal Energy Regulatory Commission (FERC) to SDG&E’s annual Electric Transmission Formula Rate filing (TO3 Cycle 6) issued an Initial Decision and an Order on Summary Judgment which authorizes SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations resulting from settlement activities for 2007 wildfire claims for that rate cycle period. This result will stand, subject to any successful appeal by the CPUC. In connection with this proceeding, the CPUC filed an appeal in the Ninth Circuit Court of Appeal of an earlier decision by the FERC denying the CPUC’s request to postpone the FERC proceeding pending CPUC action on cost recovery of the excess wildfire costs. The FERC has sought dismissal of the CPUC’s appeal on procedural grounds. The Court of Appeal has not yet ruled.
SDG&E intends to pursue recovery of costs recorded in the memorandum account allocated to SDG&E’s CPUC-regulated operations in a future application with the CPUC. SDG&E will continue to assess the potential for recovery of these costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at March 31, 2014, the resulting after-tax charge against earnings would have been up to approximately $210 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
We provide additional information about 2007 wildfire litigation costs and their recovery in Note 11.
LEGAL PROCEEDINGS
We accrue losses for legal proceedings when it is probable that a loss has been incurred and the amounts of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.
At March 31, 2014, Sempra Energy’s accrued liabilities for material legal proceedings, on a consolidated basis, were $183 million. At March 31, 2014, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $173 million and a negligible amount, respectively. At March 31, 2014, accrued liabilities of $130 million at Sempra Energy and SDG&E were related to wildfire litigation discussed below.
SDG&E
2007 Wildfire Litigation
In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and an estimated 1,141 homes destroyed.
A September 2008 staff report issued by the CPUC’s CPSD reached substantially the same conclusions as the Cal Fire reports, but also contended that the power lines involved in the Witch and Rice fires and the lashing wire involved in the Guejito fire were not properly designed, constructed and maintained. In April 2010, proceedings initiated by the CPUC to determine if any of its rules were violated were settled with SDG&E’s payment of $14.75 million.
Numerous parties have sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. They assert various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved almost all of these lawsuits. In February 2014, the Court set a February 2015 trial date for a trial to be comprised of five of the remaining cases involving plaintiffs who claim damages resulting from the Witch fire.
SDG&E filed cross-complaints against Cox and three contractors, seeking indemnification for any liability that SDG&E might incur. SDG&E settled its claims against Cox and the three contractors for a total of approximately $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.
SDG&E’s settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage for the covered period and the $824 million recovered from third parties. SDG&E has settled all of the approximately 19,000 claims brought by homeowner insurers for damage to insured property relating to the three fires. Under the settlement agreements, SDG&E has paid or will pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers’ claims against other parties potentially responsible for the fires.
The wildfire litigation also includes claims of non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has now settled almost all of the claims of the approximately 6,500 plaintiffs for a total of approximately $1.25 billion. Substantially all of the remaining plaintiffs have submitted settlement demands and damage estimates, which total approximately $250 million. SDG&E does not expect a significant number of additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.
As we discuss in Note 10, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of its reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, although such recovery will require future regulatory approval, at March 31, 2014, Sempra Energy and SDG&E have recorded assets of $377 million in Other Regulatory Assets (long-term) on their Condensed Consolidated Balance Sheets, including $358 million related to CPUC-regulated operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties. SDG&E will increase the regulatory assets if the estimate of amounts to settle remaining claims increases.
SDG&E will continue to assess the probability of recovery of these excess wildfire costs in rates. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at March 31, 2014, the resulting after-tax charge against earnings would have been up to approximately $210 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to litigate or settle pending wildfire claims. We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 10 and discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E’s cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries in rates, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s businesses, financial condition, cash flows, results of operations and prospects.
SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries in rates and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.
Since 2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. Most of the impact of this liability at March 31, 2014 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. The impact of the change in the reserves on SDG&E’s and Sempra Energy’s after-tax earnings resulted in decreases of $2.8 million and $0.3 million for the three months ended March 31, 2014 and 2013, respectively. At March 31, 2014, wildfire litigation reserves were $130 million ($75 million current and $55 million long-term). Additionally, through March 31, 2014, SDG&E has expended $374 million in excess of amounts covered by insurance and amounts recovered from third parties to pay for the settlement of wildfire claims and related costs.
Sunrise Powerlink Electric Transmission Line
The Sunrise Powerlink is a 117-mile, 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012. The Sunrise Powerlink project was approved by the CPUC in December 2008, the Bureau of Land Management in January 2009, and the United States Forest Service in July 2010. Numerous administrative appeals and legal challenges have been resolved in favor of the project. Two legal challenges remain pending.
In February 2011, opponents of the Sunrise Powerlink filed a lawsuit in Sacramento County Superior Court against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated the California Environmental Quality Act. The Superior Court denied the plaintiffs’ petition in July 2012, and the plaintiffs have appealed.
A claim for additional compensation has been submitted by one of SDG&E’s contractors on the Sunrise Powerlink project. The contractor was awarded the transmission line overhead and underground construction contract on a fixed-fee basis of $456 million after agreed-upon amendments. The contractor has asserted that it is owed additional compensation above the fixed-fee portion of the contract. In May 2013, the contractor filed claims totaling $180.3 million, including one in San Diego County for the sum of $99.2 million and the other in Imperial County for the sum of $81.1 million, seeking foreclosure of previously filed mechanics liens. In October 2013, the contractor served a Demand for Arbitration pursuant to contractual provisions. SDG&E has answered the demand and filed a counter claim against the contractor. The arbitration panel has set a March 2015 arbitration hearing date.
September 2011 Power Outage
In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diego against Arizona Public Service Company, Pinnacle West Capital Corporation and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E’s motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West Capital Corporation from the lawsuit. In September 2013, the court granted SDG&E’s motion for summary judgment and dismissed the lawsuit. In October 2013, the plaintiffs appealed the court’s dismissal of their action.
The FERC and North American Electric Reliability Corporation (NERC) Staff conducted a joint inquiry to determine the cause of the power failure and issued a report in May 2012 regarding their findings. Following that report, Staff from FERC’s Office of Enforcement (FERC Enforcement Staff) investigated potential violations of FERC’s Reliability Standards associated with the outage. In January 2014, FERC Enforcement Staff issued a Staff Notice of Alleged Violations, in which FERC Enforcement Staff alleged violations of various Reliability Standards by several entities. FERC Enforcement Staff did not allege or find any violations by SDG&E.
Smart Meters Patent Infringement Lawsuit
In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma, alleging that SDG&E’s recently installed smart meters infringed certain patents. The meters were purchased from a third party vendor that has agreed to defend and indemnify SDG&E. The lawsuit seeks injunctive relief and recovery of unspecified amounts of damages.
Lawsuit Against Mitsubishi Heavy Industries, Ltd.
On July 18, 2013, SDG&E filed a lawsuit in the Superior Court of California in the County of San Diego against Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). The lawsuit seeks to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators MHI provided to the SONGS nuclear power plant. The lawsuit asserts a number of causes of action, including fraud, based on the representations MHI made about its qualifications and ability to design generators free from defects of the kind that resulted in the permanent shutdown of the plant and further seeks to set aside the contractual limitation of damages that MHI has asserted. On July 24, 2013, MHI removed the lawsuit to the United States District Court for the Southern District of California and on August 8, 2013, MHI moved to stay the proceeding pending resolution of the dispute resolution process involving MHI and Edison arising from their contract for the purchase and sale of the steam generators. On October 16, 2013, Edison initiated an arbitration proceeding against MHI seeking damages stemming from the failure of the replacement steam generators. In late December 2013, MHI answered and filed a counter-claim against Edison. On March 14, 2014, MHI’s motion to stay the United States District Court proceeding was granted with instructions that require the parties to allow SDG&E to participate in the ongoing Edison/MHI arbitration.
Investment in Wind Farm
In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in a wind farm project and its purchase of renewable energy credits from that project. SDG&E’s contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement are subject to the satisfaction of certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement and not make the investment. In December 2013, SDG&E received a closing notice from the project developer indicating that all such conditions had been met. SDG&E responded to the closing notice asserting that the contractual conditions had not been satisfied. On December 19, 2013, SDG&E filed a complaint against the project developer in San Diego Superior Court, asking that the court determine that SDG&E is entitled to terminate both the investment contract and the power purchase agreement due to the project developer’s failure to satisfy certain conditions. The project developer filed a separate complaint against SDG&E in Montana state court asking that court to determine that SDG&E breached the investment contract and the power purchase agreement, and asking for several categories of relief, including requiring SDG&E to invest in the project, requiring SDG&E to continue performing under the power purchase agreement, and payment of damages.
On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer is disputing SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims.
SoCalGas
SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp. and Pfizer, Inc., are defendants in seven Los Angeles County Superior Court lawsuits filed beginning in April 2011 seeking recovery of unspecified amounts of damages, including punitive damages, as a result of plaintiffs’ exposure to PCBs (polychlorinated biphenyls). The lawsuits allege plaintiffs were exposed to PCBs not only through the food chain and other various sources but from PCB-contaminated natural gas pipelines owned and operated by SoCalGas. This contamination allegedly caused plaintiffs to develop cancer and other serious illnesses. Plaintiffs assert various bases for recovery, including negligence and products liability. SoCalGas has settled two of the seven lawsuits for an amount that is not significant.
Sempra Mexico
Permit Challenges and Property Disputes
Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul LNG terminal near Ensenada, Mexico. Ownership of the adjacent property is not required by any of the environmental or other regulatory permits issued for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility, and filed an action in the Federal Court challenging the permits. In February 2011, based on a complaint by the claimant, the municipality of Ensenada opened an administrative proceeding and sought to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally. Sempra Mexico expects additional Mexican court proceedings and governmental actions regarding the claimant’s assertions as to whether the terminal’s permits should be modified or revoked in any manner.
The claimant filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría Reforma Agraria (now the Secretaría de Desarrollo Agrario, Territorial y Urbano, or SEDATU) in 2006 to issue a title to him for the disputed property. In November 2013, the Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico have challenged the rulings. Sempra Mexico expects additional proceedings regarding the claims, although such proceedings are not related to the permit challenges referenced above. The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions. Sempra Energy has disputed the claims and allegations in this lawsuit.
Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization (EIA) issued to Energía Costa Azul in 2003. These cases generally allege that the conditions and mitigation measures in the EIA are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. The Mexican Supreme Court decided to exercise jurisdiction over one such case, and on March 21, 2014, issued a resolution denying the relief sought by the plaintiff on the grounds its action was not timely presented. A similar administrative challenge seeking to revoke the port concession for our marine operations at our Energía Costa Azul LNG terminal, which was filed with and rejected by the Mexican Communications and Transportation Ministry, remains on appeal in Mexican federal court as well.
Two real property cases have been filed against Energía Costa Azul in which the plaintiffs seek to annul the recorded property titles for parcels on which the Energía Costa Azul LNG terminal is situated and to obtain possession of different parcels that allegedly sit in the same place; one of these cases was dismissed in September 2013 at the direction of the state appellate court. A third complaint was served in April 2013 seeking to invalidate the contract by which Energía Costa Azul purchased another of the terminal parcels, on the grounds the purchase price was unfair. Sempra Mexico expects further proceedings on the remaining two matters.
Sempra Natural Gas
Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.
Other Litigation
As described in Note 4, Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom’s Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. The letter states that HMRC is conducting a number of investigations into VAT refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued a protective assessment of £86 million for the VAT paid in connection with these transactions. In January 2014, RBS filed a report responding to the allegations set forth in HMRC’s March 2012 letter. HMRC is currently considering the information provided in the January 2014 report, after which it will either continue its investigation and pursue the assessment, or drop the investigation and the assessment. If the assessment stands, RBS can request an internal independent review by HMRC and if the assessment still stands, appeal to an independent tribunal.
In August 2007, the U.S. Court of Appeals for the Ninth Circuit issued a decision reversing and remanding certain FERC orders declining to provide refunds regarding short-term bilateral sales up to one month in the Pacific Northwest for the January 2000 to June 2001 time period. In December 2010, the FERC approved a comprehensive settlement previously reached by Sempra Energy and RBS Sempra Commodities with the State of California. The settlement resolved all issues with regard to sales between the California Department of Water Resources and Sempra Commodities in the Pacific Northwest, but potential claims may exist regarding sales in the Pacific Northwest between Sempra Commodities and other parties. The FERC is in the process of addressing these potential claims on remand. Pursuant to the agreements related to the formation of RBS Sempra Commodities, we have indemnified RBS should the liability from the final resolution of these matters be greater than the reserves related to Sempra Commodities. Pursuant to our agreement with the Noble Group Ltd., one of the buyers of RBS Sempra Commodities’ businesses, we have also indemnified Noble Americas Gas & Power Corp. and its affiliates for all losses incurred by such parties resulting from these proceedings as related to Sempra Commodities.
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, product liability, property damage and other claims. California juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.
CONTRACTUAL COMMITMENTS
We discuss below significant changes in the first three months of 2014 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Natural Gas Contracts
SoCalGas’ natural gas purchase and pipeline capacity commitments have decreased by $45 million since December 31, 2013, primarily due to fulfillment of payment obligations and changes to forecasted gas prices in the first three months of 2014.
Sempra Natural Gas’ natural gas purchase and storage capacity commitments have decreased by $40 million since December 31, 2013, primarily due to payments on existing contracts in the first three months of 2014. Net future payments are expected to decrease by $36 million in 2014, $3 million in 2015, and $1 million in 2016 compared to December 31, 2013.
LNG Purchase Agreements
At March 31, 2014, Sempra Natural Gas has various purchase agreements with major international companies for the supply of LNG to the Energía Costa Azul and Cameron terminals. The agreements range from short-term to multi-year periods and are priced using a predetermined formula based on natural gas market indices. Although these contracts specify a number of cargoes to be delivered, under their terms, customers may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas.
Sempra Natural Gas’ commitments under all LNG purchase agreements, reflecting changes in forward prices since December 31, 2013 and actual transactions for the first three months of 2014, are expected to decrease by $121 million in 2014, and to increase by $22 million in 2015, $10 million in 2016, $19 million in 2017, $24 million in 2018 and $626 million thereafter compared to December 31, 2013. These amounts are based on forward prices of the index applicable to each contract from 2014 to 2023 and an estimated one percent escalation per year beyond 2023. The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amounts possible.
Purchased-Power Contracts
SDG&E’s commitments under purchased-power contract commitments have increased by $742 million since December 31, 2013. The increase is primarily due to new contracts associated with renewable energy development projects. Net future payments are therefore expected to increase by $11 million in 2014, decrease by $7 million in 2015, and increase by $37 million in 2016, $36 million in 2017, $34 million in 2018 and $631 million thereafter compared to December 31, 2013.
Operating Leases
In the first three months of 2014, the change to operating lease commitments at Sempra Renewables was a decrease of $82 million primarily for the deconsolidation of the Copper Mountain Solar 3 project, as we discuss in Note 3. Net future payments are expected to decrease by $2 million each year in 2014 through 2018 and $72 million thereafter.
Construction and Development Projects
In the first three months of 2014, significant net increases to contractual commitments at SDG&E were $99 million primarily for the South Bay Substation and East County Substation projects. Net future payments under these contractual commitments are expected to increase by $60 million in 2014, $36 million in 2015 and $3 million in 2016.
In the first three months of 2014, significant net increases to contractual commitments at SoCalGas were $159 million primarily for the Aliso Canyon Turbine Replacement Project and the Pipeline Safety Enhancement Program. Net future payments under these contractual commitments are expected to increase by $86 million in 2014, $55 million in 2015, $12 million in 2016 and $6 million in 2017 compared to December 31, 2013.
In the first three months of 2014, significant net increases to contractual commitments at Sempra Mexico were $9 million, all in 2014, for contracts related to the construction of the Sonora Pipeline project, a natural gas transport pipeline network.
In the first three months of 2014, the change to contractual commitments at Sempra Renewables was a decrease of $489 million primarily for the deconsolidation of the Copper Mountain Solar 3 project. Net future payments under these contractual commitments are expected to decrease by $449 million in 2014 and $40 million in 2015.
In March 2014, Cameron LNG entered into an engineering, procurement and construction contract with a joint venture consisting of CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation, to construct the Cameron liquefaction project in Hackberry, Louisiana. The scope of work under this contract includes the engineering, procurement and construction of three liquefaction trains with an aggregate nameplate capacity of approximately 13.5 million tonnes per year of LNG. The construction contract is a lump sum, date certain agreement, with a cost to Cameron LNG of approximately $6 billion as of the execution date. The lump sum price may be adjusted based on the occurrence of well-defined events, such as change orders issued by Cameron LNG, and the occurrence of other events where an adjustment to the lump sum price is customary for lump sum, date certain construction agreements.
Under the contract, Cameron LNG may, in its discretion, issue a series of three limited notices to proceed to commence certain items of work prior to issuance of a full notice to proceed to commence all contemplated work. Each limited notice to proceed authorizes the performance of additional, discrete portions of work and is subject to a firm cancellation cap if the construction contract is subsequently terminated prior to issuance of the full notice to proceed. The first limited notice to proceed, authorizing up to $27 million of expenditures, was issued in April 2014. Cameron LNG also has the right under the construction contract, subject to the terms and conditions of the joint venture documents with its partners on the project, to issue at any time the full notice to proceed to commence the construction of all work.
NUCLEAR INSURANCE
SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’s
contribution would be up to $50.93 million. This amount is subject to an annual maximum of $7.6 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.
The SONGS owners, including SDG&E, also have $2.75 billion of nuclear property, decontamination, and debris removal insurance, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through NEIL. The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $9.7 million of retrospective premiums based on overall member claims. Edison, on behalf of itself and the minority owners of SONGS (including SDG&E), has placed NEIL on notice of claims under both the property damage and outage insurance policies as a result of SONGS’ Units 2 and 3 outages in early 2012 and the resultant plant closure in June 2013.
The nuclear property insurance program 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 is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.
DEPARTMENT OF ENERGY (DOE) NUCLEAR FUEL DISPOSAL
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. This cost will be recovered through SONGS revenue unless SDG&E is able to recover the increased cost from the federal government.
We provide additional information about SONGS in Note 9.
We have six separately managed reportable segments, as follows:
|
1.
|
SDG&E
provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
|
|
2.
|
SoCalGas
is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
|
|
3.
|
Sempra South American Utilities
operates electric transmission and distribution utilities in Chile and Peru. In June 2013, we sold our interests in two Argentine utilities, which we discuss further in Note 4 above.
|
|
4.
|
Sempra Mexico
develops,
owns and operates, or holds interests in, natural gas transmission pipelines and propane and ethane systems, a natural gas distribution utility, electric generation facilities (including wind), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico.
|
|
5.
|
Sempra Renewables
develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nebraska, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.
|
|
6.
|
Sempra Natural Gas
develops, owns and operates, or holds interests in, a natural gas-fired electric generation asset, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, all within the United States.
|
Sempra South American Utilities and Sempra Mexico comprise our Sempra International operating unit. Sempra Renewables and Sempra Natural Gas comprise our Sempra U.S. Gas & Power operating unit.
We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.
The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as “All other” in the following tables consist primarily of parent organizations.
|
SEGMENT INFORMATION
|
|
|
|
|
|
|
|
|
|
|
(Dollars in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
|||||||
|
|
|
2014
|
2013
|
||||||
|
REVENUES
|
|
|
|
|
|
|
|
|
|
|
SDG&E
|
$
|
987
|
35
|
%
|
$
|
939
|
35
|
%
|
|
|
SoCalGas
|
|
1,085
|
39
|
|
|
983
|
37
|
|
|
|
Sempra South American Utilities
|
|
378
|
14
|
|
|
384
|
15
|
|
|
|
Sempra Mexico
|
|
201
|
7
|
|
|
168
|
6
|
|
|
|
Sempra Renewables
|
|
6
|
―
|
|
|
21
|
1
|
|
|
|
Sempra Natural Gas
|
|
260
|
9
|
|
|
253
|
10
|
|
|
|
Intersegment revenues(1)
|
|
(122)
|
(4)
|
|
|
(98)
|
(4)
|
|
|
|
Total
|
$
|
2,795
|
100
|
%
|
$
|
2,650
|
100
|
%
|
|
|
INTEREST EXPENSE
|
|
|
|
|
|
|
|
|
|
|
SDG&E
|
$
|
50
|
|
|
$
|
48
|
|
|
|
|
SoCalGas
|
|
17
|
|
|
|
17
|
|
|
|
|
Sempra South American Utilities
|
|
8
|
|
|
|
7
|
|
|
|
|
Sempra Mexico
|
|
4
|
|
|
|
2
|
|
|
|
|
Sempra Renewables
|
|
―
|
|
|
|
8
|
|
|
|
|
Sempra Natural Gas
|
|
32
|
|
|
|
23
|
|
|
|
|
All other
|
|
58
|
|
|
|
63
|
|
|
|
|
Intercompany eliminations
|
|
(33)
|
|
|
|
(30)
|
|
|
|
|
Total
|
$
|
136
|
|
|
$
|
138
|
|
|
|
|
INTEREST INCOME
|
|
|
|
|
|
|
|
|
|
|
SDG&E
|
$
|
―
|
|
|
$
|
1
|
|
|
|
|
Sempra South American Utilities
|
|
3
|
|
|
|
5
|
|
|
|
|
Sempra Mexico
|
|
―
|
|
|
|
1
|
|
|
|
|
Sempra Renewables
|
|
―
|
|
|
|
3
|
|
|
|
|
Sempra Natural Gas
|
|
31
|
|
|
|
11
|
|
|
|
|
All other
|
|
―
|
|
|
|
(1)
|
|
|
|
|
Intercompany eliminations
|
|
(30)
|
|
|
|
(14)
|
|
|
|
|
Total
|
$
|
4
|
|
|
$
|
6
|
|
|
|
|
DEPRECIATION AND AMORTIZATION
|
|||||||||
|
SDG&E
|
$
|
130
|
45
|
%
|
$
|
134
|
45
|
%
|
|
|
SoCalGas
|
|
105
|
37
|
|
|
100
|
34
|
|
|
|
Sempra South American Utilities
|
|
14
|
5
|
|
|
15
|
5
|
|
|
|
Sempra Mexico
|
|
16
|
6
|
|
|
16
|
5
|
|
|
|
Sempra Renewables
|
|
1
|
―
|
|
|
8
|
3
|
|
|
|
Sempra Natural Gas
|
|
17
|
6
|
|
|
20
|
7
|
|
|
|
All other
|
|
3
|
1
|
|
|
2
|
1
|
|
|
|
Total
|
$
|
286
|
100
|
%
|
$
|
295
|
100
|
%
|
|
|
INCOME TAX EXPENSE (BENEFIT)
|
|||||||||
|
SDG&E
|
$
|
83
|
|
|
$
|
51
|
|
|
|
|
SoCalGas
|
|
38
|
|
|
|
24
|
|
|
|
|
Sempra South American Utilities
|
|
15
|
|
|
|
17
|
|
|
|
|
Sempra Mexico
|
|
12
|
|
|
|
26
|
|
|
|
|
Sempra Renewables
|
|
(6)
|
|
|
|
(8)
|
|
|
|
|
Sempra Natural Gas
|
|
6
|
|
|
|
33
|
|
|
|
|
All other
|
|
(21)
|
|
|
|
35
|
|
|
|
|
Total
|
$
|
127
|
|
|
$
|
178
|
|
|
|
|
SEGMENT INFORMATION (Continued)
|
|
|
|
|
|
|
|||
|
(Dollars in millions)
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31,
|
||||||||
|
|
2014
|
2013
|
|||||||
|
EQUITY EARNINGS (LOSSES)
|
|
|
|
|
|
|
|
|
|
|
Earnings recorded before tax:
|
|
|
|
|
|
|
|||
|
Sempra Renewables
|
$
|
2
|
|
|
$
|
1
|
|
|
|
|
Sempra Natural Gas
|
|
15
|
|
|
|
9
|
|
|
|
|
Total
|
$
|
17
|
|
|
$
|
10
|
|
|
|
|
(Losses) earnings recorded net of tax:
|
|
|
|
|
|
|
|||
|
Sempra South American Utilities
|
$
|
(2)
|
|
|
$
|
(7)
|
|
|
|
|
Sempra Mexico
|
|
8
|
|
|
|
11
|
|
|
|
|
Total
|
$
|
6
|
|
|
$
|
4
|
|
|
|
|
EARNINGS (LOSSES)
|
|
|
|
|
|
|
|
|
|
|
SDG&E(2)
|
$
|
99
|
40
|
%
|
$
|
91
|
51
|
%
|
|
|
SoCalGas(3)
|
|
78
|
32
|
|
|
46
|
26
|
|
|
|
Sempra South American Utilities
|
|
35
|
14
|
|
|
37
|
21
|
|
|
|
Sempra Mexico
|
|
42
|
17
|
|
|
31
|
17
|
|
|
|
Sempra Renewables
|
|
28
|
11
|
|
|
4
|
2
|
|
|
|
Sempra Natural Gas
|
|
9
|
4
|
|
|
53
|
30
|
|
|
|
All other
|
|
(44)
|
(18)
|
|
|
(84)
|
(47)
|
|
|
|
Total
|
$
|
247
|
100
|
%
|
$
|
178
|
100
|
%
|
|
|
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
|
|
|
|||||||
|
SDG&E
|
$
|
294
|
37
|
%
|
$
|
237
|
45
|
%
|
|
|
SoCalGas
|
|
260
|
33
|
|
|
179
|
34
|
|
|
|
Sempra South American Utilities
|
|
32
|
4
|
|
|
22
|
4
|
|
|
|
Sempra Mexico
|
|
75
|
9
|
|
|
61
|
11
|
|
|
|
Sempra Renewables
|
|
99
|
12
|
|
|
6
|
1
|
|
|
|
Sempra Natural Gas
|
|
40
|
5
|
|
|
26
|
5
|
|
|
|
All other
|
|
1
|
―
|
|
|
―
|
―
|
|
|
|
Total
|
$
|
801
|
100
|
%
|
$
|
531
|
100
|
%
|
|
|
|
March 31, 2014
|
December 31, 2013
|
|||||||
|
ASSETS
|
|
|
|||||||
|
SDG&E
|
$
|
15,634
|
42
|
%
|
$
|
15,377
|
41
|
%
|
|
|
SoCalGas
|
|
9,331
|
25
|
|
|
9,147
|
25
|
|
|
|
Sempra South American Utilities
|
|
3,523
|
9
|
|
|
3,531
|
10
|
|
|
|
Sempra Mexico
|
|
3,337
|
9
|
|
|
3,246
|
9
|
|
|
|
Sempra Renewables
|
|
1,135
|
3
|
|
|
1,219
|
3
|
|
|
|
Sempra Natural Gas
|
|
7,492
|
20
|
|
|
7,200
|
19
|
|
|
|
All other
|
|
921
|
2
|
|
|
838
|
2
|
|
|
|
Intersegment receivables
|
|
(3,889)
|
(10)
|
|
|
(3,314)
|
(9)
|
|
|
|
Total
|
$
|
37,484
|
100
|
%
|
$
|
37,244
|
100
|
%
|
|
|
INVESTMENTS IN EQUITY METHOD INVESTEES
|
|
|
|||||||
|
Sempra South American Utilities
|
$
|
(5)
|
|
|
$
|
(3)
|
|
|
|
|
Sempra Mexico
|
|
384
|
|
|
|
379
|
|
|
|
|
Sempra Renewables
|
|
757
|
|
|
|
707
|
|
|
|
|
Sempra Natural Gas
|
|
336
|
|
|
|
329
|
|
|
|
|
All other
|
|
73
|
|
|
|
73
|
|
|
|
|
Total
|
$
|
1,545
|
|
|
$
|
1,485
|
|
|
|
|
(1)
|
Revenues for reportable segments include intersegment revenues of:
|
||||||||
|
|
$3 million, $18 million, $22 million and $79 million for the three months ended March 31, 2014 and $2 million, $15 million, $22 million and $59 million for the three months ended March 31, 2013 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
|
||||||||
|
(2)
|
After preferred dividends for 2013.
|
|
|
||||||
|
(3)
|
After preferred dividends.
|
|
|
||||||
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto contained in this Form 10-Q, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and the Notes thereto contained in our 2013 Annual Report on Form 10-K (Annual Report) and “Risk Factors” contained in this Form 10-Q and our Annual Report.
Sempra Energy is a Fortune 500 energy-services holding company whose operating units develop energy infrastructure, operate utilities and provide related services to their customers. Our operations are divided principally between our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), and Sempra International and Sempra U.S. Gas & Power. SDG&E and SoCalGas are separate, reportable segments. Sempra International includes two reportable segments – Sempra South American Utilities and Sempra Mexico. Sempra U.S. Gas & Power also includes two reportable segments – Sempra Renewables and Sempra Natural Gas.
This report includes information for the following separate registrants:
|
§
|
Sempra Energy and its consolidated entities
|
|
§
|
SDG&E
|
|
§
|
SoCalGas
|
References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. All references to “Sempra International” and “Sempra U.S. Gas & Power,” and to their respective principal segments, are not intended to refer to any legal entity with the same or similar name.
In the first quarter of 2013, a Sempra Energy subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), completed a private offering in the U.S. and outside of Mexico and concurrent public offering in Mexico of common stock. IEnova is a separate legal entity, formerly known as Sempra México, S.A. de C.V., comprised primarily of Sempra Energy’s operations in Mexico. IEnova is included within our Sempra Mexico reportable segment, but is not the same in its entirety as the reportable segment. In addition to the IEnova operating companies, the Sempra Mexico segment includes, among other things, certain holding companies and risk management activity. Also, IEnova’s financial results are reported in Mexico under International Financial Reporting Standards (IFRS), as required by the Mexican Stock Exchange (La Bolsa Mexicana de Valores, S.A.B. de C.V., or BMV) where the shares are traded under the symbol IENOVA. We discuss the offerings and IEnova further in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
Below are summary descriptions of our operating units and their reportable segments.
SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS
|
CALIFORNIA UTILITIES
|
||
|
MARKET
|
SERVICE TERRITORY
|
|
|
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E)
A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution
|
§
Provides electricity to 3.4 million consumers (1.4 million meters)
§
Provides natural gas to 3.2 million consumers (0.9 million meters)
|
Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
|
|
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS)
A regulated public utility; infrastructure supports natural gas distribution, transmission and storage
|
§
Residential, commercial, industrial, utility electric generation and wholesale customers
§
Covers a population of 21.3 million (5.8 million meters)
|
Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles
|
We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International or Sempra U.S. Gas & Power operating units described below.
We provide summary descriptions of our Sempra International and Sempra U.S. Gas & Power businesses below.
|
SEMPRA INTERNATIONAL
|
||
|
MARKET
|
GEOGRAPHIC REGION
|
|
|
SEMPRA SOUTH AMERICAN UTILITIES
Infrastructure supports electric transmission and distribution
|
§
Provides electricity to approximately 640,000 customers in Chile and 996,000 customers in Peru
|
§
Chile
§
Peru
|
|
SEMPRA MEXICO
Develops, owns and operates, or holds interests in:
§
natural gas transmission pipelines and propane and ethane systems
§
a natural gas distribution utility
§
electric generation facilities, including wind
§
a terminal for the import of liquefied natural gas (LNG)
§
marketing operations for the purchase of LNG and the purchase and sale of natural gas
|
§
Natural gas
§
Wholesale electricity
§
Liquefied natural gas
|
§
Mexico
|
We discuss the following in Results of Operations:
|
§
|
Overall results of our operations and factors affecting those results
|
|
§
|
Our segment results
|
|
§
|
Significant changes in revenues, costs and earnings between periods
|
Our earnings increased by $69 million (39%) to $247 million in the three months ended March 31, 2014, while diluted earnings per share for the three-month period increased by $0.27 per share (38%) to $0.99 per share.
Due to the delay in the issuance of a final decision in the California Utilities’ 2012 General Rate Case (GRC), the California Utilities’ California Public Utilities Commission (CPUC) base revenues for the first quarter of 2013 were unchanged from what was authorized for 2011. The final decision in the 2012 GRC, which was issued by the CPUC in May 2013, was effective retroactive to January 1, 2012. As a result, the California Utilities’ CPUC base revenues for the first quarter of 2014 are based on the revenues authorized for the 2012 Test Year plus the amount authorized for attrition for each of 2013 and 2014. Had the 2012 GRC been in effect in the first quarter of 2013, Sempra Energy’s earnings for the first quarter of 2013 would have been $29 million higher in total, including $17 million higher at SDG&E and $12 million higher at SoCalGas. These amounts were recorded in earnings in the second quarter of 2013. We provide additional information on the 2012 GRC in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
The net increases in our earnings and diluted earnings per share were primarily impacted by the following increases (decreases), by segment:
SDG&E
|
§
|
$17 million reduced earnings in 2013 due to the delay in receiving the final 2012 GRC decision, as discussed above
|
|
§
|
$(9) million ($0.04 per share) charge to adjust the total loss from plant closure (in addition to the amount recorded in 2013) associated with SDG&E’s investment in the San Onofre Nuclear Generating Station (SONGS) based upon a proposed settlement agreement filed with the CPUC in April 2014, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein
|
SoCalGas
|
§
|
$14 million higher operating margin and newly recovered costs as a result of the 2012 GRC
|
|
§
|
$12 million reduced earnings in 2013 due to the delay in receiving the final 2012 GRC decision, as discussed above
|
Sempra Mexico
|
§
|
$10 million lower income tax expense including the effects from Mexican currency and translation adjustments
|
|
§
|
$9 million allowance for funds used during construction (AFUDC) related to equity associated with construction of the natural gas pipeline in Sonora
|
|
§
|
$(9) million decrease in Sempra Mexico’s earnings for earnings attributable to noncontrolling interests at IEnova following its March 2013 offerings of 18.9 percent of IEnova common stock
|
Sempra Renewables
|
§
|
$16 million ($0.07 per share) gain from the sale of a 50-percent equity interest in Copper Mountain Solar 3
|
Sempra Natural Gas
|
§
|
$(44) million ($0.18 per share) gain on the sale of one 625-megawatt (MW) block of Sempra Natural Gas’ 1,250-MW Mesquite Power natural gas-fired power plant in the first quarter of 2013
|
Parent and Other
|
§
|
$63 million ($0.25 per share) income tax expense in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings
|
The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”
SEGMENT RESULTS
The following section is a discussion of earnings (losses) by Sempra Energy segment, as presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.
|
EARNINGS BY SEGMENT – CALIFORNIA UTILITIES
|
|
(Dollars in millions)
|
![[GRAPH1.GIF]](https://content.edgar-online.com/edgar_conv_img/2014/05/02/0000086521-14-000025_GRAPH1.GIF)
Due to the delay in the issuance of a final decision in the California Utilities’ 2012 GRC, the California Utilities’ CPUC base revenues for the first quarter of 2013 were unchanged from what was authorized for 2011. The final decision in the 2012 GRC, which was issued by the CPUC in May 2013, was effective retroactive to January 1, 2012. As a result, the California Utilities’ CPUC base revenues for the first quarter of 2014 are based on the revenues authorized for the 2012 Test Year plus the amount authorized for attrition for each of 2013 and 2014. Had the 2012 GRC been in effect in the first quarter of 2013, SDG&E’s and SoCalGas’ earnings for the first quarter of 2013 would have been higher by $17 million and $12 million, respectively. These amounts were recorded in earnings in the second quarter of 2013. We provide additional information on the 2012 GRC in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
SDG&E
Our SDG&E segment recorded earnings of:
|
§
|
$99 million in the three months ended March 31, 2014
|
|
§
|
$91 million in the three months ended March 31, 2013 ($92 million before preferred dividends)
|
The increase in earnings of $8 million (9%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$17 million reduced earnings in 2013 due to the delay in receiving the final 2012 GRC decision as discussed above; and
|
|
§
|
$4 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs;
offset by
|
|
§
|
$9 million charge to adjust the total loss from plant closure (in addition to the amount recorded in 2013) associated with SDG&E’s investment in SONGS based upon a proposed settlement agreement filed with the CPUC, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein;
|
|
§
|
$3 million lower electric transmission margin, primarily due to lower Federal Energy Regulatory Commission (FERC)-authorized return on equity; and
|
|
§
|
$3 million loss of revenue from SONGS due to the early closure of the plant in the second quarter of 2013.
|
SoCalGas
Our SoCalGas segment recorded earnings of:
|
§
|
$78 million in the three months ended March 31, 2014 (both before and after preferred dividends)
|
|
§
|
$46 million in the three months ended March 31, 2013 (both before and after preferred dividends)
|
The increase in earnings of $32 million (70%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$12 million reduced earnings in 2013 due to the delay in receiving the final 2012 GRC decision as discussed above;
|
|
§
|
$11 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs; and
|
|
§
|
$3 million due to expensing of costs associated with the Transmission Integrity Management Program in the first quarter of 2013 that are now being fully recovered (balanced) in revenues pursuant to the 2012 GRC.
|
|
EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL
|
|
(Dollars in millions)
|
![[GRAPH2.GIF]](https://content.edgar-online.com/edgar_conv_img/2014/05/02/0000086521-14-000025_GRAPH2.GIF)
Sempra South American Utilities
Our Sempra South American Utilities segment recorded earnings of:
|
§
|
$35 million in the three months ended March 31, 2014
|
|
§
|
$37 million in the three months ended March 31, 2013
|
The decrease in earnings of $2 million (5%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$5 million lower earnings from foreign currency effects; and
|
|
§
|
$2 million higher interest expense in Chile related to inflationary effect on local bonds;
offset by
|
|
§
|
a $7 million impairment charge in 2013 related to our investment in two Argentine natural gas utility holding companies.
|
Sempra Mexico
Our Sempra Mexico segment recorded earnings of:
|
§
|
$42 million in the three months ended March 31, 2014
|
|
§
|
$31 million in the three months ended March 31, 2013
|
The increase in earnings of $11 million (35%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$10 million lower income tax expense including the effects from foreign currency adjustments; and
|
|
§
|
$9 million AFUDC related to equity associated with construction of the natural gas pipeline in Sonora;
offset by
|
|
§
|
$10 million earnings attributable to noncontrolling interests at IEnova in 2014 compared to $1 million in 2013.
|
|
EARNINGS BY SEGMENT – SEMPRA U.S. GAS & POWER
|
|
(Dollars in millions)
|
![[GRAPH3.GIF]](https://content.edgar-online.com/edgar_conv_img/2014/05/02/0000086521-14-000025_GRAPH3.GIF)
Sempra Renewables
Our Sempra Renewables segment recorded earnings of:
|
§
|
$28 million in the three months ended March 31, 2014
|
|
§
|
$4 million in the three months ended March 31, 2013
|
The increase in earnings of $24 million in the three months ended March 31, 2014 was primarily due to:
|
§
|
$16 million gain from the sale of a 50-percent equity interest in Copper Mountain Solar 3; and
|
|
§
|
$7 million higher deferred income tax benefits, due in part to a $5 million reduction of income tax benefits in 2013 as a result of Treasury Grant sequestration.
|
Sempra Natural Gas
Our Sempra Natural Gas segment recorded earnings of:
|
§
|
$9 million in the three months ended March 31, 2014
|
|
§
|
$53 million in the three months ended March 31, 2013
|
The decrease in earnings of $44 million (83%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$44 million gain in 2013 on the sale of a 625-MW block of its Mesquite Power plant, net of related expenses; and
|
|
§
|
$9 million higher 2013 earnings primarily from LNG cargo marketing operations, offset by the impact of higher natural gas prices in 2014;
offset by
|
|
§
|
$4 million lower operating costs, primarily depreciation, at the Mesquite Power plant due to the classification of the remaining 625-MW block as an asset held for sale; and
|
|
§
|
$4 million improved results primarily from mark-to-market losses driven by change in natural gas prices in 2013, partially offset by lower natural gas marketing activities in 2014.
|
Parent and Other
Losses for Parent and Other were
|
§
|
$44 million in the three months ended March 31, 2014
|
|
§
|
$84 million in the three months ended March 31, 2013
|
The decrease in losses of $40 million (48%) in the three months ended March 31, 2014 was primarily due to:
|
§
|
$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings;
offset by
|
|
§
|
$12 million income tax expense for planned repatriation of current year foreign earnings; and
|
|
§
|
$6 million higher net interest expense.
|
CHANGES IN REVENUES, COSTS AND EARNINGS
This section contains a discussion of the differences between periods in the specific line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.
Utilities Revenues
Our utilities revenues include
Natural gas revenues at:
|
§
|
SDG&E
|
|
§
|
SoCalGas
|
|
§
|
Sempra Mexico’s Ecogas México, S. de R.L. de C.V. (Ecogas)
|
|
§
|
Sempra Natural Gas’ Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas)
|
Electric revenues at:
|
§
|
SDG&E
|
|
§
|
Sempra South American Utilities’ Chilquinta Energía and Luz del Sur
|
Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Condensed Consolidated Statements of Operations.
The California Utilities
The current regulatory framework for SoCalGas and SDG&E permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.
The regulatory framework also permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in the next year through rates.
The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:
|
UTILITIES REVENUES AND COST OF SALES
|
|||||
|
(Dollars in millions)
|
|||||
|
|
|
Three months ended March 31,
|
|||
|
|
|
2014
|
2013
|
||
|
Electric revenues:
|
|
|
|
|
|
|
SDG&E
|
$
|
811
|
$
|
772
|
|
|
Sempra South American Utilities
|
|
354
|
|
360
|
|
|
Eliminations and adjustments
|
|
(2)
|
|
(1)
|
|
|
|
Total
|
|
1,163
|
|
1,131
|
|
Natural gas revenues:
|
|
|
|
|
|
|
SoCalGas
|
|
1,085
|
|
983
|
|
|
SDG&E
|
|
176
|
|
167
|
|
|
Sempra Mexico
|
|
33
|
|
27
|
|
|
Sempra Natural Gas
|
|
47
|
|
42
|
|
|
Eliminations and adjustments
|
|
(19)
|
|
(16)
|
|
|
|
Total
|
|
1,322
|
|
1,203
|
|
Total utilities revenues
|
$
|
2,485
|
$
|
2,334
|
|
|
Cost of electric fuel and purchased power:
|
|
|
|
|
|
|
SDG&E
|
$
|
266
|
$
|
209
|
|
|
Sempra South American Utilities
|
|
244
|
|
238
|
|
|
|
Total
|
$
|
510
|
$
|
447
|
|
Cost of natural gas:
|
|
|
|
|
|
|
SoCalGas
|
$
|
508
|
$
|
454
|
|
|
SDG&E
|
|
75
|
|
76
|
|
|
Sempra Mexico
|
|
22
|
|
16
|
|
|
Sempra Natural Gas
|
|
20
|
|
14
|
|
|
Eliminations and adjustments
|
|
(5)
|
|
(4)
|
|
|
|
Total
|
$
|
620
|
$
|
556
|
Sempra Energy Consolidated
Electric Revenues
During the three months ended March 31, 2014, our electric revenues increased by $32 million (3%) to $1.2 billion primarily due to a $39 million increase at SDG&E, which included
|
§
|
$57 million increase in cost of electric fuel and purchased power; and
|
|
§
|
$27 million increase primarily due to higher authorized revenue in the 2012 GRC decision and attritions for 2013 and 2014. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SDG&E’s authorized revenue for the three months ended March 31, 2013 was essentially unchanged from the 2011 authorized revenue;
offset by
|
|
§
|
$31 million lower recovery of costs associated with CPUC-authorized refundable programs, including $20 million due to lower operation and maintenance expenses at SONGS, which revenues are fully offset in operation and maintenance expenses; and
|
|
§
|
$13 million loss of revenue associated with SDG&E’s capital investment in SONGS due to the early closure of the plant.
|
The increase in our electric revenues in 2014 was partially offset by a $6 million decrease at Sempra South American Utilities, which was primarily due to foreign currency exchange rate effects, offset by higher rates and volumes at both Luz del Sur and Chilquinta Energía.
Our utilities’ cost of electric fuel and purchased power increased by $63 million (14%) to $510 million in the three months ended March 31, 2014 due to:
|
§
|
$57 million increase at SDG&E, which we discuss below; and
|
|
§
|
$6 million increase at our South American utilities driven primarily by higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects.
|
We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.
Natural Gas Revenues
During the three months ended March 31, 2014, Sempra Energy’s natural gas revenues increased by $119 million (10%) to $1.3 billion, and the cost of natural gas increased by $64 million (12%) to $620 million. The increase in natural gas revenues included
|
§
|
an increase in cost of natural gas sold at SoCalGas offset by lower demand, as we discuss below;
|
|
§
|
increases of $28 million and $10 million at SoCalGas and SDG&E, respectively, primarily due to higher authorized revenues in the 2012 GRC decision and the attritions for 2013 and 2014. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, authorized revenue for the three months ended March 31, 2013 was essentially unchanged from the 2011 authorized revenue; and
|
|
§
|
$22 million higher recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.
|
We discuss the changes in natural gas revenues and the cost of natural gas individually for SDG&E and SoCalGas below.
SDG&E: Electric Revenues and Cost of Electric Fuel and Purchased Power
The table below shows electric revenues for SDG&E. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in cost, electric revenues recorded during a period are impacted by customer billing cycles causing a difference between customer billings and recorded or authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
During the three months ended March 31, 2014, SDG&E’s electric revenues increased by $39 million (5%) to $811 million primarily due to:
|
§
|
$57 million increase in cost of electric fuel and purchased power primarily due to the incremental cost and purchases of renewable energy, and increased cost of other purchased power primarily due to higher power prices, partially offset by lower sales volume in the residential customer class primarily due to warmer than normal temperatures in the first quarter of 2014 as compared to cooler than normal temperatures in the first quarter of 2013; and
|
|
§
|
$27 million increase primarily due to higher authorized revenue in the 2012 GRC decision and the attritions for 2013 and 2014. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SDG&E’s authorized revenue for the three months ended March 31, 2013 was essentially unchanged from the 2011 authorized revenue;
offset by
|
|
§
|
$31 million lower recovery of costs associated with CPUC-authorized refundable programs, including $20 million lower operation and maintenance expenses at SONGS, which revenues are fully offset in operation and maintenance expenses; and
|
|
§
|
$13 million loss of revenue associated with SDG&E’s capital investment in SONGS due to the early closure of the plant.
|
We do not include in the Condensed Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts that are allocated to SDG&E by the California Department of Water Resources. However, we do include the associated volumes and distribution revenues in the table above. We provide further discussion of these contracts in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas
The tables below show natural gas revenues for SDG&E and SoCalGas. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
|
SDG&E
|
||||||||||
|
NATURAL GAS SALES AND TRANSPORTATION
|
||||||||||
|
(Volumes in billion cubic feet, dollars in millions)
|
||||||||||
|
|
|
Natural Gas Sales
|
Transportation
|
Total
|
||||||
|
Customer class
|
Volumes
|
Revenue
|
Volumes
|
Revenue
|
Volumes
|
Revenue
|
||||
|
Three months ended March 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
10
|
$
|
118
|
―
|
$
|
―
|
10
|
$
|
118
|
|
|
Commercial and industrial
|
5
|
|
34
|
2
|
|
3
|
7
|
|
37
|
|
|
Electric generation plants
|
―
|
|
―
|
6
|
|
1
|
6
|
|
1
|
|
|
|
|
15
|
$
|
152
|
8
|
$
|
4
|
23
|
|
156
|
|
Other revenues
|
|
|
|
|
|
|
|
|
12
|
|
|
Balancing accounts
|
|
|
|
|
|
|
|
|
8
|
|
|
Total(1)
|
|
|
|
|
|
|
|
$
|
176
|
|
|
Three months ended March 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
13
|
$
|
133
|
―
|
$
|
1
|
13
|
$
|
134
|
|
|
Commercial and industrial
|
5
|
|
30
|
2
|
|
3
|
7
|
|
33
|
|
|
Electric generation plants
|
―
|
|
―
|
6
|
|
3
|
6
|
|
3
|
|
|
|
|
18
|
$
|
163
|
8
|
$
|
7
|
26
|
|
170
|
|
Other revenues
|
|
|
|
|
|
|
|
|
10
|
|
|
Balancing accounts
|
|
|
|
|
|
|
|
|
(13)
|
|
|
Total(1)
|
|
|
|
|
|
|
|
$
|
167
|
|
|
(1)
|
Includes sales to affiliates of $1 million in each of 2014 and 2013.
|
|||||||||
During the three months ended March 31, 2014, SDG&E’s natural gas revenues increased by $9 million (5%) to $176 million, and the cost of natural gas sold decreased by $1 million (1%) to $75 million. The increase in revenues was primarily due to $10 million higher authorized revenue in the 2012 GRC decision and the attritions for 2013 and 2014. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SDG&E’s authorized revenue for the three months ended March 31, 2013 was essentially unchanged from the 2011 authorized revenue.
SDG&E’s average cost of natural gas for the three months ended March 31, 2014 was $5.29 per thousand cubic feet (Mcf) compared to $4.19 per Mcf for the corresponding period in 2013, a 26-percent increase of $1.10 per Mcf, resulting in higher revenues and cost of $16 million. The increase in the cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $17 million.
|
SOCALGAS
|
||||||||||
|
NATURAL GAS SALES AND TRANSPORTATION
|
||||||||||
|
(Volumes in billion cubic feet, dollars in millions)
|
||||||||||
|
|
|
Natural Gas Sales
|
Transportation
|
Total
|
||||||
|
Customer class
|
Volumes
|
Revenue
|
Volumes
|
Revenue
|
Volumes
|
Revenue
|
||||
|
Three months ended March 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
69
|
$
|
732
|
1
|
$
|
3
|
70
|
$
|
735
|
|
|
Commercial and industrial
|
28
|
|
237
|
73
|
|
64
|
101
|
|
301
|
|
|
Electric generation plants
|
―
|
|
―
|
41
|
|
9
|
41
|
|
9
|
|
|
Wholesale
|
―
|
|
―
|
39
|
|
7
|
39
|
|
7
|
|
|
|
|
97
|
$
|
969
|
154
|
$
|
83
|
251
|
|
1,052
|
|
Other revenues
|
|
|
|
|
|
|
|
|
28
|
|
|
Balancing accounts
|
|
|
|
|
|
|
|
|
5
|
|
|
Total(1)
|
|
|
|
|
|
|
|
$
|
1,085
|
|
|
Three months ended March 31, 2013:
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
91
|
$
|
771
|
1
|
$
|
3
|
92
|
$
|
774
|
|
|
Commercial and industrial
|
31
|
|
203
|
72
|
|
60
|
103
|
|
263
|
|
|
Electric generation plants
|
―
|
|
―
|
38
|
|
9
|
38
|
|
9
|
|
|
Wholesale
|
―
|
|
―
|
49
|
|
7
|
49
|
|
7
|
|
|
|
|
122
|
$
|
974
|
160
|
$
|
79
|
282
|
|
1,053
|
|
Other revenues
|
|
|
|
|
|
|
|
|
26
|
|
|
Balancing accounts
|
|
|
|
|
|
|
|
|
(96)
|
|
|
Total(1)
|
|
|
|
|
|
|
|
$
|
983
|
|
|
(1)
|
Includes sales to affiliates of $18 million in 2014 and $15 million in 2013.
|
|||||||||
During the three months ended March 31, 2014, SoCalGas’ natural gas revenues increased by $102 million (10%) to $1.1 billion, and the cost of natural gas sold increased by $54 million (12%) to $508 million. The revenue increase included
|
§
|
an increase in the market price of natural gas purchased, as we discuss below;
|
|
§
|
$28 million increase primarily due to higher authorized revenue in the 2012 GRC decision and the attritions for 2013 and 2014. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SoCalGas’ authorized revenue for the three months ended March 31, 2013 was essentially unchanged from the 2011 authorized revenue; and
|
|
§
|
$22 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses.
|
SoCalGas’ average cost of natural gas for the three months ended March 31, 2014 was $5.27 per Mcf compared to $3.70 per Mcf for the corresponding period in 2013, a 42-percent increase of $1.57 per Mcf, resulting in higher revenues and cost of $151 million. The increase in the average cost of natural gas sold was offset by lower demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013, which resulted in lower revenues and cost of $97 million.
Other Utilities: Revenues and Cost of Sales
Revenues generated by Chilquinta Energía and Luz del Sur are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. The basis for the tariffs do not meet the requirement necessary for treatment under applicable accounting principles generally accepted in the United States of America (U.S. GAAP) for regulatory accounting. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable U.S. GAAP, similar to the California Utilities.
The table below summarizes natural gas and electric revenues for our utilities outside of California for the three-month periods ended March 31, 2014 and 2013:
|
OTHER UTILITIES
|
|||||||
|
NATURAL GAS AND ELECTRIC REVENUES
|
|
|
|
|
|
|
|
|
(Dollars in millions)
|
|||||||
|
|
|
Three months ended
March 31, 2014
|
Three months ended
March 31, 2013
|
||||
|
|
Volumes
|
Revenue
|
Volumes
|
Revenue
|
|||
|
Natural Gas Sales (billion cubic feet):
|
|
|
|
|
|
|
|
|
Sempra Mexico — Ecogas
|
6
|
$
|
33
|
6
|
$
|
27
|
|
|
Sempra Natural Gas:
|
|
|
|
|
|
|
|
|
Mobile Gas (including transportation)
|
11
|
|
36
|
11
|
|
34
|
|
|
Willmut Gas
|
1
|
|
11
|
1
|
|
8
|
|
|
Total
|
18
|
$
|
80
|
18
|
$
|
69
|
|
|
|
|
|
|
|
|
|
|
|
Electric Sales (million kilowatt hours):
|
|
|
|
|
|
|
|
|
Sempra South American Utilities:
|
|
|
|
|
|
|
|
|
Luz del Sur
|
1,851
|
$
|
208
|
1,746
|
$
|
204
|
|
|
Chilquinta Energía
|
788
|
|
134
|
761
|
|
141
|
|
|
|
|
2,639
|
|
342
|
2,507
|
|
345
|
|
Other service revenues
|
|
|
12
|
|
|
15
|
|
|
Total
|
|
$
|
354
|
|
$
|
360
|
|
Energy-Related Businesses: Revenues and Cost of Sales
The table below shows revenues and cost of sales for our energy-related businesses.
During the three months ended March 31, 2014, revenues from our energy-related businesses decreased by $6 million (2%) to $310 million. The decrease included
|
§
|
$20 million higher intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas; and
|
|
§
|
$15 million lower revenues at Sempra Renewables mainly due to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in the third quarter of 2013;
offset by
|
|
§
|
$27 million higher revenues at Sempra Mexico primarily due to higher natural gas and power prices; and
|
|
§
|
$2 million increase at Sempra Natural Gas in 2014 mainly from mark-to-market losses driven by changes in natural gas prices in 2013, offset by lower natural gas marketing activities in 2014 and lower revenues from its LNG cargo marketing operations, offset by the favorable impact of higher natural gas prices in 2014.
|
During the three months ended March 31, 2014, the cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $27 million (24%) to $138 million primarily due to:
|
§
|
a $24 million increase at Sempra Mexico primarily due to higher natural gas costs; and
|
|
§
|
a $21 million increase at Sempra Natural Gas primarily due to higher natural gas costs;
offset by
|
|
§
|
$19 million higher intercompany eliminations of costs primarily associated with sales between Sempra Mexico and Sempra Natural Gas.
|
Operation and Maintenance
Sempra Energy Consolidated
For the three months ended March 31, 2014, our operation and maintenance expenses decreased by $48 million (7%) to $676 million primarily due to SDG&E, which we discuss below.
SDG&E
For the three months ended March 31, 2014, SDG&E’s operation and maintenance expenses decreased by $45 million (15%) to $252 million primarily due to:
|
§
|
$32 million lower expenses associated with CPUC-authorized refundable programs, including $20 million due to lower operation and maintenance expenses at SONGS, for which all costs incurred are fully recovered in revenue (refundable program expenses); and
|
|
§
|
$12 million decrease at Otay Mesa VIE.
|
SoCalGas
For the three months ended March 31, 2014, SoCalGas’ operation and maintenance expenses decreased by $1 million to $305 million primarily due to:
|
§
|
$23 million lower operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs);
offset by
|
|
§
|
$22 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses).
|
Gain on Sale of Equity Interest and Assets
In the first quarter of 2014, Sempra Renewables recorded a pretax gain of $27 million ($16 million after-tax) from the sale of a 50-percent equity interest in Copper Mountain Solar 3. In the first quarter of 2013, Sempra Natural Gas completed the sale of one 625-MW block of its Mesquite Power natural gas-fired power plant for $371 million, resulting in a pretax gain on sale of the asset of $74 million ($44 million after-tax).
Other Income, Net
Sempra Energy Consolidated
For the three months ended March 31, 2014, other income, net, increased by $3 million (8%) to $40 million primarily due to:
|
§
|
$9 million AFUDC related to equity associated with construction of the Sonora natural gas pipeline at Sempra Mexico;
offset by
|
|
§
|
$5 million lower net gains on interest rate and foreign exchange instruments.
|
Income Taxes
The table below shows the income tax expense and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.
|
INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
|
|||||||||||
|
(Dollars in millions)
|
|||||||||||
|
|
|
|
Three months ended March 31,
|
||||||||
|
|
|
|
2014
|
|
2013
|
||||||
|
|
|
|
|
|
Effective
|
|
|
|
|
Effective
|
|
|
|
|
|
Income Tax
|
|
Income
|
|
|
Income Tax
|
|
Income
|
|
|
|
|
|
Expense
|
|
Tax Rate
|
|
|
Expense
|
|
Tax Rate
|
|
|
Sempra Energy Consolidated
|
$
|
127
|
|
33
|
%
|
$
|
178
|
|
51
|
%
|
|
|
SDG&E
|
|
83
|
|
45
|
|
|
51
|
|
39
|
|
|
|
SoCalGas
|
|
38
|
|
33
|
|
|
24
|
|
34
|
|
|
Sempra Energy Consolidated
The decrease in income tax expense in the three months ended March 31, 2014 was due to a lower effective tax rate offset by higher pretax income. The change in the effective income tax rate was primarily due to:
|
§
|
$63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings in Note 5 of the Notes to Condensed Consolidated Financial Statements herein;
offset by
|
|
§
|
a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS that management believes may no longer be recoverable from customers in rates pursuant to the proposed settlement agreement to resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS outage that we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements herein; and
|
|
§
|
$12 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru.
|
As noted in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report, we have planned to repatriate a portion of future earnings beginning in 2014 from our subsidiaries in Mexico and Peru. Currently, all repatriated earnings from January 1, 2014 forward are subject to U.S. income tax (with a credit for foreign income taxes) and repatriation from Peru is subject to local country withholding tax. Because any repatriation would only be from earnings in 2014 and later years, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2013. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.
Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted are factored into the forecasted effective tax rate and their impact is recognized proportionately over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software expenditures, repairs to certain utility plant fixed assets, renewable energy income tax credits, deferred income tax benefits related to renewable energy projects, exclusions from taxable income of the equity portion of AFUDC, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, Mexican currency translation and inflation adjustments, and deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.
Chilean Tax Reform
In April 2014, Chile’s President presented a tax reform proposal (Tax Reform Bill) to the Chilean Congress which introduces a number of amendments to the current laws and regulations and would impact Chilquinta Energía in our Sempra South American Utilities segment. The Tax Reform Bill would increase the corporate tax rate from the current 20% to 25% on a graduated basis over a 4-year period, starting in 2014.
The Tax Reform Bill also would eliminate the Accumulated Tax Profit Fund, Fondo de Utilidades Tributables (FUT). Under current law, shareholders are generally not taxed on business profits until those profits are distributed. The Tax Reform Bill would eliminate FUT that allowed for deferral and create a new system starting in 2017, under which shareholders would be taxed on an accrual basis. Annual taxable profits of Chilean companies would be deemed automatically distributed to their shareholders at year-end, and shareholders would pay current taxes on the taxable income. The new system would require that shareholders, in our case Sempra Energy, pay 35% (including the 25% corporate tax) on an accrual basis on the taxable income generated by their investments.
The proposed tax reform is still in the normal legislative process, and a tax reform law is expected to be enacted before year-end.
SDG&E
The increase in SDG&E’s income tax expense in the three months ended March 31, 2014 was primarily due to a higher effective tax rate and also to higher pretax income. The higher effective tax rate was primarily due to the $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS discussed above.
The results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is not included in Sempra Energy’s federal or state income tax returns but is consolidated for financial statement purposes, and therefore, Sempra Energy Consolidated’s and SDG&E’s effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate. We discuss Otay Mesa VIE further in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
SoCalGas
The increase in SoCalGas’ income tax expense in the three months ended March 31, 2014 was primarily due to higher pretax income offset by higher deductions for certain repairs expenditures that are capitalized for financial statement purposes.
Due to the extension of bonus depreciation, Sempra Energy, SDG&E and SoCalGas generated large U.S. federal net operating losses (NOLs) in 2011 and 2012. We discuss further the impact of NOLs on Sempra Energy, SDG&E and SoCalGas in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity
Our Mexican subsidiaries have U.S. dollar denominated cash balances, receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes.
The fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar, with regard to Mexican monetary assets and liabilities, and Mexican inflation are subject to Mexican income tax and thus may expose us to fluctuations in our income tax expense. The income tax expense of Sempra Mexico is impacted by these factors. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage these exposures.
For Sempra Energy Consolidated, the impacts on the three-month periods ended March 31, 2014 and 2013 related to the factors described above are as follows:
|
MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
|
||||||
|
(Dollars in millions)
|
||||||
|
|
|
|
Three months ended March 31,
|
|||
|
|
|
|
2014
|
2013
|
||
|
Income tax expense on currency exchange
|
|
|
|
|
||
|
|
rate movement of monetary assets and liabilities
|
|
$
|
―
|
$
|
(2)
|
|
Translation of non-U.S. deferred income tax balances
|
|
―
|
|
(7)
|
||
|
Income tax expense on inflation
|
|
|
(1)
|
|
(1)
|
|
|
|
Total impact on income taxes
|
|
|
(1)
|
|
(10)
|
|
After-tax gains on Mexican peso exchange rate
|
|
|
|
|
|
|
|
|
instruments (included in Other Income, Net)
|
|
|
―
|
|
4
|
|
Net impacts on Sempra Energy Condensed
|
|
|
|
|
|
|
|
|
Consolidated Statements of Operations
|
|
$
|
(1)
|
$
|
(6)
|
Earnings Attributable to Noncontrolling Interests
Sempra Energy Consolidated
Earnings attributable to noncontrolling interests were $19 million for the three months ended March 31, 2014 compared to losses of $2 million for the same period in 2013. The net change of $21 million included
|
§
|
$2 million of earnings attributable to noncontrolling interest at Otay Mesa VIE in 2014 compared to $11 million losses in 2013; and
|
|
§
|
$9 million increase in earnings attributable to noncontrolling interests of IEnova.
|
Earnings
We discuss variations in earnings by segment above in “Segment Results.”
We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. In addition, we may meet our cash requirements through the issuance of securities, including short-term and long-term debt securities, distributions from our equity method investments and project financing.
Our committed lines of credit provide liquidity and support commercial paper. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities, expiring in March 2017. At Sempra Energy and the California Utilities, the agreements are syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders. No single lender has greater than a 7-percent share in any agreement.
The table below shows the amount of available funds at March 31, 2014:
Sempra Energy Consolidated
We believe that
these available funds and cash flows from operations, distributions from equity method investments and
securities issuances, and project financing and partnering in joint ventures, combined with current cash and cash equivalents balances, will be adequate to fund operations, including to:
|
§
|
finance capital expenditures
|
|
§
|
meet liquidity requirements
|
|
§
|
fund shareholder dividends
|
|
§
|
fund new business acquisitions or start-ups
|
|
§
|
repay maturing long-term debt
|
In March 2014, SoCalGas publicly offered and sold $250 million of 4.45-percent notes maturing in 2044. In 2013, Sempra Energy and SDG&E publicly offered and sold debt securities totaling $500 million and $450 million, respectively, maturing in 2023. In 2013, Sempra Mexico issued debt securities totaling $408 million, U.S. dollar equivalent, maturing in 2018 and 2023. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact certain of our Sempra International and Sempra U.S. Gas & Power businesses before we would reduce funds necessary for the ongoing needs of our utilities. We continuously monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.
The net decrease in Sempra Energy Consolidated cash and cash equivalents at March 31, 2014 compared to December 31, 2013 of approximately $60 million was primarily due to payment of common dividends declared in December 2013 and paid in January 2014 of $154 million, offset by the receipt of $66 million cash proceeds, net of $2 million cash sold, from the sale of a 50-percent equity interest in Copper Mountain Solar 3 in March 2014. In March 2014, we also received $84 million in net proceeds from a construction loan related to Copper Mountain Solar 3. The loan was deconsolidated upon the sale. We discuss the Copper Mountain Solar 3 transactions further in Notes 3 and 6 of the Notes to Condensed Consolidated Financial Statements herein.
At March 31, 2014, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $704 million. As we discuss in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report, we plan to repatriate a portion of future earnings beginning in 2014 from certain of our non-U.S. subsidiaries in Mexico and Peru. Because this potential repatriation would only be from earnings since January 1, 2014, it does not change our current assertion that we intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2013. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.
We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. Changes in asset values, which are dependent on the activity in the equity and fixed income markets, have not affected the trust funds’ abilities to make required payments, but along with a number of other factors such as changes to discount rates, assumed rates of returns and regulations, may impact funding requirements for pension and other postretirement benefit plans and the nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.
We discuss our principal credit agreements more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.
Our short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, temporarily finance capital expenditures, and fund new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary source of short-term debt funding in the first quarter of 2014.
California Utilities
SDG&E and SoCalGas expect that available funds, cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements.
SoCalGas declared and paid $50 million in common dividends in 2013. However, as a result of the increase in SoCalGas’ capital investment programs over the next few years, and the increase in SoCalGas’ authorized common equity weighting as approved by the CPUC in the cost of capital proceeding, management expects that SoCalGas’ dividends on common stock will be reduced, when compared to the dividends on common stock declared on an annual basis historically, or temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
As a result of SDG&E’s large capital investment program over the past few years and the level of capital investment in 2013, SDG&E did not pay common dividends to Sempra Energy in 2013. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E expects to resume the declaration and payment of dividends on its common stock in 2014.
SDG&E uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power and the amount billed to customers in rates. Primarily as a result of delays in the CPUC issuing final decisions on SDG&E’s ERRA Trigger filings and its annual filing for its 2014 ERRA revenue requirement, as of March 31, 2014, SDG&E’s ERRA balance is undercollected by approximately $525 million. Until such time as SDG&E is authorized to include the amount it has requested to recover in its 2014 ERRA revenue requirement filing, management expects the undercollected balance in ERRA to increase. As a result, SDG&E will continue to issue commercial paper as needed to ensure adequate liquidity to meet its operational and capital program requirements. We discuss the status of the ERRA filings further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and provide information on how the increasing undercollected balance in ERRA has impacted SDG&E in our discussion of “Cash Flows From Operating Activities” below.
Sempra South American Utilities
We expect projects at Chilquinta Energía and Luz del Sur to be funded by available funds, funds internally generated by those businesses and by external borrowings.
Sempra Mexico
We expect projects in Mexico to be funded through a combination of available funds, funds internally generated by the Mexico businesses, debt issuances, project financing, partnering in joint ventures and the proceeds from IEnova’s debt and equity offerings in early 2013.
Sempra Renewables
We expect Sempra Renewables to require funds for the development of and investment in renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, and partnering in joint ventures. The Sempra Renewables projects have planned in-service dates through 2016. In March 2014, Sempra Renewables received a $356 million construction loan related to Copper Mountain Solar 3, as we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. Sempra Renewables made an initial draw-down on the loan of $97 million. Later in March 2014, Sempra Renewables sold a 50-percent equity interest in Copper Mountain Solar 3 to Consolidated Edison Development (ConEdison Development). Sempra Renewables’ interest in Copper Mountain Solar 3 is now accounted for under the equity method and its long-term debt was deconsolidated upon the sale. Sempra Renewables received $66 million in net cash from the sale.
Sempra Natural Gas
We expect Sempra Natural Gas to require funding for the expansion of its portfolio of projects, including natural gas storage and pipelines and natural gas liquefaction facility. Funding for the development and expansion of its natural gas storage and transmission projects may be financed through a combination of operating cash flow and funding from the parent. In January 2014, management approved a plan to sell the remaining 625-MW block of the Mesquite Power plant, which we expect to yield cash proceeds at the time of sale. Sempra Natural Gas also plans to develop a natural gas liquefaction export facility at its Cameron LNG terminal. Sempra Natural Gas expects the majority of the liquefaction project to be project-financed with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions in a joint venture agreement. We expect to provide the majority of our share of equity through the contribution of the existing Cameron LNG facility at an agreed value of approximately $1 billion and also by cash generated from each liquefaction train as it comes on line.
Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash, guarantees or letters of credit to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when the fair value of the contract with our counterparty exceeds established thresholds. We have no collateral posted and $2 million of collateral owed to counterparties at March 31, 2014 pursuant to these requirements.
CASH FLOWS FROM OPERATING ACTIVITIES
|
CASH PROVIDED BY OPERATING ACTIVITIES
|
||||||||
|
(Dollars in millions)
|
||||||||
|
|
2014
|
2014 Change
|
2013
|
|||||
|
Sempra Energy Consolidated
|
$
|
904
|
$
|
69
|
8
|
%
|
$
|
835
|
|
SDG&E
|
|
261
|
|
(3)
|
(1)
|
|
|
264
|
|
SoCalGas
|
|
427
|
|
16
|
4
|
|
|
411
|
Sempra Energy Consolidated
Cash provided by operating activities at Sempra Energy increased in 2014 primarily due to:
|
§
|
$128 million decrease in accounts receivable in 2014 compared to a $33 million increase in 2013, primarily due to a $78 million decrease at SoCalGas primarily due to lower natural gas sales and a $42 million decrease in natural gas sales at Sempra Natural Gas in 2014; and
|
|
§
|
$124 million increase in accounts payable in 2014 compared to a $42 million decrease in 2013, primarily due to higher average cost of natural gas purchased at SoCalGas in 2014;
offset by
|
|
§
|
$85 million decrease in inventory in 2014 compared to a $137 million decrease in 2013, primarily due to higher net natural gas withdrawal volume at SoCalGas in 2013;
|
|
§
|
$11 million decrease in net overcollected regulatory balancing accounts in 2014 at SDG&E and SoCalGas (including long-term amounts included in regulatory assets) compared to a $145 million increase in 2013. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below; and
|
|
§
|
$27 million increase in income tax payments in 2014 compared to 2013.
|
SDG&E
Cash provided by operating activities at SDG&E decreased in 2014 primarily due to:
|
§
|
$28 million increase in net undercollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to a $6 million increase in 2013. The higher increase in the undercollected regulatory balancing accounts was primarily due to:
|
|
□
|
$110 million increase in the undercollected balancing account for electric resource cost in 2014 compared to an increase of $38 million in 2013,
offset by
|
|
□
|
$40 million due to collection of costs in 2014 related to the adoption of the 2012 GRC, and
|
|
□
|
$6 million decrease in the undercollected balancing account for the electric transmission access charge in 2014 compared to an increase of $13 million in 2013; and
|
|
§
|
$4 million decrease in accounts payable in 2014 compared to a $16 million increase in 2013;
offset by
|
|
§
|
$26 million increase in accounts receivable in 2013.
|
SoCalGas
Cash provided by operating activities at SoCalGas increased in 2014 primarily due to:
|
§
|
$81 million increase in accounts payable in 2014 compared to a $73 million decrease in 2013. The increase in accounts payable in 2014 was primarily due to the higher average cost of natural gas purchased, and the decrease in 2013 was primarily due to lower purchase volume;
|
|
§
|
$45 million higher net income, adjusted for noncash items included in earnings, in 2014 compared to 2013; and
|
|
§
|
$78 million decrease in accounts receivable in 2014 compared to a $27 million decrease in 2013 primarily due to lower natural gas sales volumes in 2014;
offset by
|
|
§
|
$17 million increase in net overcollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to $151 million increase in 2013. The increase in 2013 was primarily due to a $132 million increase in the overcollected balance in the core customer fixed costs balancing account; and
|
|
§
|
$24 million decrease in inventory in 2014 compared to a $117 million decrease in 2013, primarily due to higher net natural gas withdrawal volume in 2013.
|
The table below shows the contributions to pension and other postretirement benefit plans for the three months ended March 31, 2014.
|
CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
|
||||
|
(Dollars in millions)
|
||||
|
|
Three months ended March 31, 2014
|
|||
|
|
|
|
Other
|
|
|
|
Pension
|
Postretirement
|
||
|
|
Benefits
|
Benefits
|
||
|
Sempra Energy Consolidated
|
$
|
15
|
$
|
1
|
|
SDG&E
|
|
1
|
|
―
|
|
SoCalGas
|
|
2
|
|
―
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
CASH USED IN INVESTING ACTIVITIES
|
||||||||
|
(Dollars in millions)
|
||||||||
|
|
2014
|
2014 Change
|
2013
|
|||||
|
Sempra Energy Consolidated
|
$
|
(770)
|
$
|
608
|
375
|
%
|
$
|
(162)
|
|
SDG&E
|
|
(297)
|
|
57
|
24
|
|
|
(240)
|
|
SoCalGas
|
|
(377)
|
|
(45)
|
(11)
|
|
|
(422)
|
Sempra
Energy Consolidated
Cash used in investing activities at Sempra Energy increased in 2014 primarily due to:
|
§
|
$270 million increase in capital expenditures; and
|
|
§
|
$371 million of proceeds received in 2013 from Sempra Natural Gas’ sale of a 625-MW block of its Mesquite Power plant;
offset by
|
|
§
|
$66 million, net of $2 million cash sold, of proceeds received in 2014 from the sale of a 50-percent equity interest in Copper Mountain Solar 3.
|
SDG&E
Cash used in investing activities at SDG&E increased in 2014 primarily due to a $57 million increase in capital expenditures.
SoCalGas
Cash used in investing activities at SoCalGas decreased in 2014 due to:
|
§
|
$126 million decrease in advances to Sempra Energy in 2014;
offset by
|
|
§
|
$81 million increase in capital expenditures.
|
ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS
The amounts and timing of capital expenditures are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC and the FERC. However, in 2014, we expect to make annual capital expenditures and investments of approximately $3.2 billion. These expenditures include
|
§
|
$2.2 billion at the California Utilities for capital projects and plant improvements ($1.1 billion at SDG&E and $1.1 billion at SoCalGas)
|
|
§
|
$1 billion at our other subsidiaries for capital projects in Mexico and South America, and development of natural gas and renewable generation projects
|
The California Utilities’ 2014 planned capital expenditures and investments include
|
§
|
$610 million for improvements to SDG&E’s natural gas and electric distribution systems
|
|
§
|
$320 million for improvements to SDG&E’s electric transmission systems
|
|
§
|
$100 million at SDG&E for substation expansions (transmission)
|
|
§
|
$30 million for SDG&E’s electric generation plants and equipment
|
|
§
|
$880 million for improvements to SoCalGas’ distribution and transmission systems and storage, and for pipeline safety
|
|
§
|
$190 million for SoCalGas’ advanced metering infrastructure
|
|
§
|
$30 million for SoCalGas’ other natural gas projects
|
The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.
In 2014, the expected capital expenditures and investments of approximately $1 billion (excluding amounts expended by joint ventures and net of anticipated project financing and joint venture structures as noted below) at our other subsidiaries include
Sempra South American Utilities
|
§
|
approximately $150 million to $200 million for capital projects in South America (approximately $100 million to $150 million in Peru and approximately $50 million in Chile)
|
Sempra Mexico
|
§
|
approximately $300 million to $350 million for capital projects in Mexico, including approximately $300 million for the development of the Sonora Pipeline project developed solely by Sempra Mexico
|
|
§
|
approximately $450 million of expenditures for pipeline projects within our joint venture with Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company). We expect these expenditures within the joint venture to be funded by the joint venture’s cash flows from operations, project financing and additional contributions from its partners
|
|
§
|
approximately $180 million of expenditures for the Energía Sierra Juárez renewable wind project to be primarily funded by project financing
|
Sempra Renewables
The following amounts are net of anticipated project financing and joint venture structures:
|
§
|
approximately $300 million for the development of renewable projects, including
|
|
§
|
approximately $100 million for investment in Copper Mountain Solar 3, a 250-MW solar project located near Boulder City, Nevada
|
|
§
|
approximately $100 million for investment in the California solar partnership with ConEdison Development that we discuss in Note 4 of the Notes to Condensed Consolidated Financial Statements herein
|
|
§
|
approximately $80 million for investment in the 75-MW Broken Bow 2 Wind project in Custer County, Nebraska
|
Sempra Natural Gas
|
§
|
approximately $200 million for development of natural gas transportation and storage projects
|
Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of AFUDC related to debt, but exclude the portion of AFUDC related to equity. At Sempra Mexico, the amounts also exclude AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
CASH FLOWS FROM FINANCING ACTIVITIES
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|||||||
|
(Dollars in millions)
|
|||||||
|
|
2014
|
2014 Change
|
2013
|
||||
|
Sempra Energy Consolidated
|
$
|
(193)
|
$
|
(513)
|
|
$
|
320
|
|
SDG&E
|
|
21
|
|
26
|
|
|
(5)
|
|
SoCalGas
|
|
(45)
|
|
(45)
|
|
|
―
|
Sempra Energy Consolidated
The change in cash flows from financing activities at Sempra Energy from 2013 to 2014 was primarily due to:
|
§
|
$574 million net proceeds received in 2013 from the sale of noncontrolling interests at Sempra Mexico;
|
|
§
|
$493 million higher payments on debt, including higher payments of long-term debt of $649 million ($1.1 billion in 2014 compared to $405 million in 2013), offset by lower payments of commercial paper and other short-term debt with maturities greater than 90 days of $156 million ($84 million in 2014 compared to $240 million in 2013); and
|
|
§
|
$69 million decrease in short-term debt in 2014 compared to $43 million decrease in 2013;
offset by
|
|
§
|
$580 million higher issuances of debt, including an increase in issuances of commercial paper with maturities greater than 90 days of $592 million ($792 million in 2014 compared to $200 million in 2013), offset by a decrease in issuances of long-term debt of $12 million ($396 million in 2014 compared to $408 million in 2013).
|
SDG&E
The change in cash flows from financing activities at SDG&E from 2013 to 2014 was primarily due to $31 million issuances of short-term debt in 2014.
SoCalGas
Cash used in financing activities at SoCalGas in 2014 included:
|
§
|
$250 million payment of long-term debt; and
|
|
§
|
$42 million payment of short-term debt;
offset by
|
|
§
|
$248 million net proceeds from the issuance of long-term debt.
|
COMMITMENTS
We discuss significant changes to contractual commitments at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
CREDIT RATINGS
The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first three months of 2014. In January 2014, Moody’s increased SDG&E’s and SoCalGas’ unsecured debt rating to A1 with a stable outlook.
Our credit ratings may affect the rates at which borrowings bear interest and of commitment fees on available unused credit. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
CALIFORNIA UTILITIES
Overview
The California Utilities’ operations have historically provided relatively stable earnings and liquidity. However, for the next few years, SoCalGas intends to limit its common stock dividends to reinvest its earnings in significant capital projects.
The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss in various sections of this report and below. We discuss certain regulatory matters below and in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E may also continue to be significantly impacted by matters at SONGS. We discuss SONGS below, in Notes 9 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.
Joint Matters
Natural Gas Pipeline Operations Safety Assessments
Pending the outcome of the various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur incremental expense and capital investment associated with its natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, Pacific Gas and Electric Company (PG&E) and Southwest Gas filed implementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. In their 2011 filing with the CPUC, the California Utilities estimated the total cost for Phase 1 of the two-phase plan to be $3.1 billion ($2.5 billion for SoCalGas and $600 million for SDG&E) over the 10-year period of 2012 to 2022. The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery. The costs that are the subject of these plans were outside the scope of the 2012 General Rate Case proceedings concluded in 2013. If the CPUC were to decide that the incremental capital investment not be considered as incremental rate base outside the GRC process, that this incremental capital investment earn a return on rate base lower than what is otherwise authorized, or that cost recovery not be allowed for other incremental costs not eligible for rate base recovery, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects upon commencement of this program.
On April 15, 2014, the assigned Administrative Law Judge issued a proposed decision in the Triennial Cost Allocation Proceeding (TCAP) proceeding addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan filing (PSEP PD). While the PSEP PD is ambiguous in a number of key areas, management has determined that if the PSEP PD is adopted in its current form, it:
|
§
|
approves the utilities’ model for implementing PSEP;
|
|
§
|
approves a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers of interim costs incurred to implement PSEP, which are recorded in the regulatory accounts authorized by the CPUC as noted above;
|
|
§
|
approves balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and
|
|
§
|
establishes the criteria to determine the amounts that would not be eligible for cost recovery, including certain costs incurred or to be incurred associated with records review, the cost of pressure testing pipelines installed after 1955 for which the company has not found sufficient records of testing, and any undepreciated balances for pipelines that were replaced as a result of this program.
|
The utilities are seeking additional clarification on a number of key areas within the proposed decision and plan to file comments with the CPUC by the deadline of May 5, 2014.
Through March 31, 2014, SDG&E and SoCalGas have incurred, and recorded in the CPUC-authorized regulatory account, $2 million and $56 million, respectively, associated with the implementation of their PSEPs.
We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
Safety Enforcement
California Senate Bill (SB) 291, enacted in October 2013, requires the CPUC to develop and implement a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegating citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. SB 291 requires the CPUC to implement the enforcement program for gas safety by July 1, 2014 and for electric safety by January 1, 2015. In exercising the citation authority, the CPUC staff will take into account voluntary reporting of potential violations, voluntary resolution efforts undertaken, prior history of violations, the gravity of the violation, and the degree of culpability. The CPUC is planning to adopt an administrative limit on the maximum monetary penalty that may be set by the CPUC staff.
In December 2011, the CPUC adopted a gas safety citation program whereby natural gas distribution companies can be fined by CPUC staff for violations of the CPUC’s safety standards or federal standards. Each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. In September 2013, the CPUC issued its Standard Operating Procedures setting forth its principles and management process for the gas safety citation program.
SDG&E Matters
2007 Wildfire Litigation
In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees total approximately $2.4 billion, which is in excess of the $1.1 billion of liability insurance coverage and the approximately $824 million recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. At March 31, 2014, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $377 million in Other Regulatory Assets (long-term), of which $358 million is related to CPUC-regulated operations and $19 million is related to FERC-regulated operations, for costs incurred and the estimated settlement of pending claims. However, SDG&E’s cash flow may be materially adversely affected by timing differences between the resolution of claims and recoveries in rates, which may extend over a number of years. In addition, recovery in rates will require future regulatory approval, and a failure to obtain substantial or full recovery, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations.
SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of recoveries in rates and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.
Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E will record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at March 31, 2014, the resulting after-tax charge against earnings would have been up to approximately $210 million. In addition, in periods following any such conclusion by SDG&E that recovery is no longer probable, Sempra Energy’s and SDG&E’s earnings will be adversely impacted by increases in the estimated costs to litigate or settle pending wildfire claims. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
We provide additional information concerning these matters in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.
SONGS
We discuss regulatory and other matters related to SONGS in the Notes to Condensed Consolidated Financial Statements herein as follows:
In Note 9:
|
§
|
SONGS Outage and Retirement
|
|
§
|
Proposed Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation into the SONGS Outage (SONGS OII)
|
|
§
|
Nuclear Regulatory Commission Proceedings
|
|
§
|
Nuclear Decommissioning and Funding
|
|
§
|
Nuclear Decommissioning Trusts
|
In Note 11:
|
§
|
Lawsuit Against Mitsubishi Heavy Industries, Ltd.
|
|
§
|
Nuclear Insurance
|
|
§
|
Department of Energy Nuclear Fuel Disposal
|
Investment in Wind Farm
In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in the Rim Rock wind farm project. SDG&E and the project developer are in dispute regarding whether all conditions precedent in the contribution agreement have been achieved by the developer of the project. As a result, SDG&E has not made the investment, and the project developer and SDG&E are in dispute regarding SDG&E’s contractual obligation to invest in the project, as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Electric Rate Reform – State of California Assembly Bill 327
In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This new law restores the authority to establish electric residential rates for electric utility companies in California to the CPUC and removes the rate caps established in AB 1X adopted in early 2001 during California’s energy crisis, as well as SB 695 adopted in 2009. Additionally, the bill provides the CPUC the authority to adopt up to a $10.00 monthly fixed charge for all non-California Alternative Rates for Energy (CARE) residential customers and up to a $5.00 monthly fixed charge for CARE customers, effective January 1, 2015. The CPUC will implement AB 327 through its various regulatory proceedings. Meaningful rate reform is necessary due to, among other issues, the increased power supply from renewable energy sources and the growth in distributed and local power generation. If the CPUC fails to reform SDG&E’s rate structures to maintain competitive and affordable electric rates, such failure could have a material adverse effect on SDG&E’s business, cash flows, financial condition, results of operations and/or prospects. For additional discussion, see “Risk Factors” in the Annual Report.
Industry Developments and Capital Projects
We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect the California Utilities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
SEMPRA INTERNATIONAL
As we discuss in “Cash Flows From Investing Activities,” our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in “Capital Resources and Liquidity” herein and in the “Capital Resources and Liquidity” and “Factors Influencing Future Performance” sections of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
Sempra South American Utilities
Overview
In April 2011, Sempra South American Utilities increased its investment in two utilities in South America, Chilquinta Energía and Luz del Sur. In connection with our increased interests in these utilities, Sempra Energy has $902 million in goodwill on its Condensed Consolidated Balance Sheet at March 31, 2014. Goodwill is subject to impairment testing, annually and under other potential circumstances, which may cause its fair value to vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. We discuss the acquisition in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report.
Sempra South American Utilities is also expected to provide earnings from construction projects when completed and from other investments, but will require substantial funding for these investments.
Sempra South American Utilities has historically provided relatively stable earnings and liquidity, and its performance will depend primarily on the ratemaking and regulatory process, environmental regulations and economic conditions.
Revenues at Chilquinta Energía are based on tariffs set by the National Energy Commission (Comisión Nacional de Energía, or CNE) every four years. Rates for four-year periods related to distribution and sub-transmission are reviewed separately on an alternating basis every two years. In late 2011, Chilquinta Energía initiated the process to establish its distribution rates for the period from November 2012 to October 2016. This process was completed in November 2012, with rates published in April 2013, and tariff adjustments going into effect retroactively from November 2012. This resulted in a 3.2 percent decrease in rates.
In April 2013, the CNE completed the process to establish sub-transmission rates for the period January 2011 to December 2014, with tariff adjustments going into effect retroactively from January 2011. In 2013, the CNE published the methodology to be used to recalculate the average node prices (price at which distribution companies buy energy from generators) for years 2011, 2012 and 2013 and requested comments. We expect the CNE’s final decision in the first half of 2014.
The next reviews are scheduled to be completed, with tariff adjustments also going into effect, in January 2015 for sub-transmission, and again for distribution in November 2016.
Luz del Sur serves primarily regulated customers in Peru and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN). The rates are reviewed and adjusted every four years. OSINERGMIN’s final distribution rate setting resolution for the 2013-2017 period was published in October 2013 and went into effect on November 1, 2013. There was no material change in the rates.
In April 2014, Chile’s President presented a tax reform proposal to the Chilean Congress which introduces a number of amendments to the current laws and regulations, as we discuss in “Changes in Revenues, Costs and Earnings – Income Taxes” above.
Santa Teresa
Luz del Sur is in the final stages of construction of Santa Teresa, a 100-MW hydroelectric power plant in Peru’s Cusco region. It is scheduled to be completed in 2014.
Transmission Projects
Chilquinta Energía has entered into two 50-percent owned joint ventures, Eletrans S.A. and Eletrans II S.A., with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct transmission lines in Chile.
In May 2012, Eletrans S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend 150 miles, and we estimate the project will cost approximately $150 million and be completed in 2017.
In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 70 miles, and we estimate the project will cost approximately $80 million and be completed in 2018.
The projects will be financed by the joint venture partners. Other financing may be pursued upon completion of the projects.
Sempra Mexico
Overview
Sempra Mexico is expected to provide earnings from construction projects when completed and from other investments. We expect projects in Mexico to be funded through a combination of available funds, funds internally generated by the Mexico businesses, debt issuances, project financing, partnering in joint ventures, and the proceeds from IEnova’s debt and equity offerings in early 2013. We discuss the debt offering further in Note 5 of the Notes to the Consolidated Financial Statements in the Annual Report.
In March 2013, Sempra Mexico sold common shares of IEnova in a private placement in the U.S. and outside of Mexico and, concurrently, in a registered public offering in Mexico, as we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein. The shares sold represent approximately 18.9 percent of the ownership interests in IEnova, which reduce our earnings from Sempra Mexico and have a dilutive effect on our earnings per share. The earnings attributable to IEnova’s noncontrolling interests were $10 million for the three months ended March 31, 2014. The approximately $574 million in net proceeds from the offerings is being used primarily for general corporate purposes and for the funding of IEnova’s current investments and ongoing expansion plans.
We discuss the impact of Mexican tax reform in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
Pipeline Projects
In October 2012, Sempra Mexico was awarded two contracts by Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) to build and operate an approximately 500-mile pipeline network (Sonora Pipeline) to transport natural gas from the U.S.-Mexico border south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa along the Gulf of California. The network will be comprised of two segments that will interconnect to the U.S. interstate pipeline system. We estimate it will cost approximately $1 billion. The first segment of the project, approximately 300 miles, began construction in September 2013 and is expected to be completed in the second half of 2014, and the remaining segment is expected to be completed in the second half of 2016. The capacity is fully contracted by CFE under two 25-year contracts denominated in U.S. dollars.
In December 2012, through its joint venture with PEMEX, Sempra Mexico executed an ethane transportation services agreement with PEMEX to construct and operate an approximately 140-mile pipeline (Ethane Pipeline) to transport ethane from Tabasco, Mexico to Veracruz, Mexico. We estimate it will cost approximately $330 million and be funded by the joint venture without additional capital contributions from the partners. It is expected to be completed in the first half of 2015. The capacity is fully contracted by PEMEX under a 21-year contract denominated in U.S. dollars.
In January 2013, PEMEX announced that the first phase of the Los Ramones pipeline project was assigned to and will be developed by our joint venture with PEMEX. The project will consist of a 70-mile natural gas pipeline (Los Ramones I) from the northern portion of the state of Tamaulipas bordering the United States to Los Ramones in the Mexican state of Nuevo León. The capacity is fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate.
In addition, in March 2014, our joint venture with PEMEX and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 275 miles and two compression stations, which will connect with the first phase of Los Ramones and run to the vicinity of San Luis Potosi, with an estimated cost of approximately $1 billion. When these agreements become effective, our joint venture with PEMEX will have a 50-percent interest in the project. We expect expenditures for the project to be funded by the joint venture’s cash flows from operations and project financing, plus additional contributions from its partners. Any additional contributions from partners will depend on the amount of project financing obtained. The transportation services agreement is subject to governmental approvals. Upon completion, the pipeline’s capacity would be fully contracted under a 25-year transportation services agreement with PEMEX denominated in Mexican pesos, with a contract rate based on the U.S. dollar investment, adjusted annually for inflation and fluctuation of the exchange rate.
Energía Sierra Juárez
In April 2011, SDG&E entered into a 20-year contract for up to 155 MW of renewable power supplied from the first phase of Sempra Mexico’s Energía Sierra Juárez wind generation project in Baja California, Mexico. The contract was approved by the CPUC in March 2012 and by the FERC in July 2012. In October 2013, Sempra Mexico issued full notice to proceed to the construction contractor. Sempra Mexico intends to develop and finance the project within the framework of a joint venture. In April 2014, we entered into an agreement to sell 50 percent of our equity in the first phase of Energía Sierra Juárez to InterGen N.V. The transaction is subject to regulatory approvals in Mexico and the U.S.
SEMPRA U.S. GAS & POWER
Sempra Renewables
Overview
Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with utilities. The renewable energy projects have planned in-service dates through 2016. These projects require construction financing which may come from a variety of sources including operating cash flow, project financing, funds from the parent, partnering in joint ventures and, potentially, other forms of equity sales. The varying costs of these alternative financing sources impact the projects’ returns.
Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as Renewables Portfolio Standards (RPS). Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions.
Copper Mountain Solar
Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. When fully developed, the project will be capable of producing up to approximately 450 MW of solar power; it is being developed in multiple phases as power sales become contracted. Copper Mountain Solar is comprised of three separate projects. Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, which includes the 10-MW facility previously referred to as El Dorado Solar. PG&E has contracted for all of the solar power at Copper Mountain Solar 1 for 20 years.
Copper Mountain Solar 2 began construction in December 2011 and will total 150 MW when completed. Copper Mountain Solar 2 is divided into two phases, with the first phase of 92 MW placed in service in November 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at Copper Mountain Solar 2 for 25 years. In July 2013, we completed the sale of 50 percent of our equity in Copper Mountain Solar 2 to ConEdison Development as we discuss in Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements in the Annual Report.
Copper Mountain Solar 3 started construction in March 2013 and will total 250 MW when completed. Copper Mountain Solar 3 will be placed in service as each of the ten blocks of solar panels is installed and is planned to be entirely in service by late 2015. The cities of Los Angeles and Burbank have contracted for all of the solar power at Copper Mountain Solar 3 for 20 years. In addition to solar power, the power sales agreement provides the cities of Los Angeles and Burbank the option to purchase the Copper Mountain Solar 3 facility at years 10, 15 and 20 of the contract term, or upon earlier termination of the agreement. In March 2014, we completed the sale of 50 percent of our equity in Copper Mountain Solar 3 to ConEdison Development, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.
Mesquite Solar
Mesquite Solar is a photovoltaic generation facility under development by Sempra Renewables in Maricopa County, Arizona. If fully developed, the project will be capable of producing up to approximately 700 MW of solar power. Construction on the first phase (Mesquite Solar 1) of 150 MW was completed in December 2012. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years. In September 2013, we completed the sale of 50 percent of our equity in Mesquite Solar 1 to ConEdison Development as we discuss in Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements in the Annual Report.
Broken Bow 2 Wind Project
In September 2013, Sempra Renewables acquired the rights to develop the Broken Bow 2 Wind project in Custer County, Nebraska. Sempra Renewables will develop the 75-MW wind farm. We began construction on the project in 2013, and we expect the project to be fully operational in late 2014. Nebraska Public Power District has contracted for all of the wind energy from the project for 25 years. Sempra Renewables intends to develop and finance the project within the framework of a joint venture.
California Solar Partnership with ConEdison Development
In March 2014, Sempra Renewables and ConEdison Development entered into an agreement to partner in four solar projects in California. The projects are those in ConEdison Development’s CED California Holdings, LLC portfolio, which consists of the 50-MW Alpaugh 50, the 20-MW Alpaugh North and the 20-MW White River 1 facilities in Tulare County, and the 20-MW Corcoran 1 facility in Kings County. The renewable power from all of the projects has been sold under long-term contracts. The agreement is subject to regulatory approvals, which we expect to receive during the second quarter of 2014. Upon consummation of the transactions under the agreement, Sempra Renewables and ConEdison Development will each own a 50-percent interest in the four solar facilities.
Sempra Natural Gas
Overview
In June 2011, Sempra Natural Gas entered into a 25-year power contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada. The contract was expanded to a total of 271 MW in February 2013. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power from its Mesquite Power plant delivered to the Palo Verde hub beginning in January 2015.
In February 2013, Sempra Natural Gas completed the sale of one 625-MW block of its Mesquite Power plant to the Salt River Project Agricultural Improvement and Power District for $371 million in cash. Sempra Natural Gas retained ownership of the second 625-MW block of the Mesquite Power plant that will support the contract with the participating SPPR Group members.
In January 2014, management approved a plan to market and sell the remaining 625-MW block of the plant. We expect to complete the sale in 2014. We discuss the plan to sell the second 625-MW block of Mesquite Power in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. In the event of the sale, the contract with the SPPR Group may be assigned to the buyer.
Sempra Natural Gas is currently progressing with plans for the Cameron liquefaction project, a development project to utilize its Cameron LNG terminal for the liquefaction of natural gas and export of LNG, discussed below. The objective is to obtain long-term contracts for liquefaction services that allow us to fully utilize our existing regasification infrastructure while minimizing our future additional capital investment. Although the Cameron terminal is not fully contracted for regasification, given our current progress on the liquefaction project, we do not expect to contract or sell any additional long-term LNG import capacity at the Cameron terminal. The terminal will be completely contracted for both liquefaction and regasification capacity under the terms of the liquefaction and regasification tolling capacity agreement as discussed below.
Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates a natural gas pipeline, the Rockies Express Pipeline (REX), which links the Rocky Mountains region to the upper Midwest and the eastern United States. Sempra Rockies Marketing, a subsidiary of Sempra Natural Gas, has an agreement for capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity. Certain capacity release commitments totaling $22 million concluded during 2013. Accordingly, new contracting activity related to that capacity may not be sufficient to offset all of our capacity payments to Rockies Express. These contracts currently provide west-to-east transportation services. On April 30, 2014, Rockies Express launched a binding open season for 1.2 billion cubic feet (Bcf) per day of east-to-west firm transportation capacity originating at or near Clarington, Ohio. Rockies Express has already secured binding financial commitments for this capacity at rates of $0.50 per dekatherm (Dth) for twenty years, but if Rockies Express receives higher bids in the open season, the shippers who have already provided commitments will have the opportunity to match the higher bids. We expect this capacity to be in service by mid-2015. In addition, Rockies Express is constructing the Seneca lateral, a project that will connect REX to natural gas production sources in Ohio with 200,000 Dth per day of capacity planned to be in service in mid-2014. Rockies Express has also notified FERC that it intends to expand the lateral to 600,000 Dth per day of capacity.
Our carrying value in Rockies Express at March 31, 2014 is $336 million. We recorded noncash, after-tax impairment charges totaling $239 million in 2012 to write down our investment in the partnership. We discuss our investment in Rockies Express and the impairment charges in Notes 4 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.
Our natural gas storage assets include operational and development assets at Bay Gas in Alabama and Mississippi Hub in Mississippi, as well as our development project, LA Storage in Louisiana. These assets could be well positioned to capitalize on new opportunities that emerge associated with the increase in natural gas production and consumption in the U.S. In particular, LA Storage could be well positioned to support LNG export from Cameron and other liquefaction projects, if anticipated cash flows support further investment. However, changes in the U.S. natural gas market could also lead to diminished natural gas storage values.
Historically, the value of natural gas storage services has positively correlated with the difference between the seasonal prices of natural gas, among other factors. In general, over the past several years, seasonal differences in natural gas prices have declined, which have contributed to lower prices for storage services. As our legacy (higher rate) sales contracts mature at Bay Gas and Mississippi Hub, replacement sales contract rates could be lower than has historically been the case. Lower sales revenues may not be offset by cost reductions, which could lead to depressed asset values. These market conditions could result in the need to perform recovery testing of our recorded asset values. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent excess book value over fair value is indicated, an impairment charge would be required to be recorded. The book value of our natural gas storage assets at March 31, 2014 is $1.3 billion.
Currently, Sempra Natural Gas has 30 Bcf of operational working natural gas storage capacity (15 Bcf at Bay Gas and 15 Bcf at Mississippi Hub). We are currently developing another 13 Bcf of capacity with planned in-service dates through the first half of 2014 and may, over the long term, develop as much as 76 Bcf of total storage capacity.
Sempra Natural Gas’ natural gas storage facilities and projects include
|
§
|
Bay Gas, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Natural Gas owns 91 percent of the project. It is the easternmost salt dome storage facility on the Gulf Coast, with direct service to the Florida market and markets across the Southeast, Mid-Atlantic and Northeast regions.
|
|
§
|
Mississippi Hub, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.
|
|
§
|
LA Storage, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.
|
Cameron Liquefaction Project
The Cameron liquefaction project will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. In January 2012, the DOE approved Cameron LNG’s application for authorization to export LNG to Free Trade Agreement countries.
In 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. to develop a natural gas liquefaction export facility at the Cameron LNG terminal. The Cameron liquefaction project is expected to be comprised of three liquefaction trains and is being designed to a nameplate capacity of 13.5 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. We expect to receive all necessary regulatory approvals, close the project financing, and start construction in 2014. This should allow us to achieve commercial operation of all three trains in 2018, and have the first year of full production in 2019. The anticipated incremental investment in the three-train liquefaction project, subject to final design specifications, is estimated to be approximately $6 billion to $7 billion, excluding capitalized interest and other financing costs, the majority of which will be project-financed and the balance provided by the project partners through the joint-venture agreements we discuss below. The total cost of the facility, including the cost of our original facility plus interest during construction, financing costs and required reserves, is estimated to be approximately $9 billion to $10 billion.
It is our expectation that substantially all of our equity contribution requirement will be covered by the contribution of our existing assets. If construction, financing or other capital costs are higher than we currently expect or we are not able to leverage the project at the levels we currently anticipate, we may have to contribute additional cash, which may include cash generated from each liquefaction train as it comes on line. In May 2013, we signed a joint venture agreement with affiliates of GDF SUEZ S.A., Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha (NYK)), and Mitsui & Co., Ltd. each to acquire 16.6 percent equity in the existing facilities and the liquefaction project. We will have a 50.2-percent interest in the joint venture. The joint venture agreement, the three tolling agreements and the engineering, procurement and construction contracts described below are subject to a final investment decision to proceed by each party, finalization of permit authorizations and securing financing commitments, as well as other customary conditions.
If one or more of the parties decides not to move forward with the project, or if we are unable to arrange suitable financing, the project may be substantially delayed, reduced or terminated. If the project is terminated, we may not recover our share of any project development or other related costs expended, and we may be required to write off our share of any such previously capitalized costs. In addition, this project may be delayed, reduced or terminated in the event we are unable to obtain all of the necessary permits, licenses and authorizations in a timely manner.
The commercial development agreements executed in 2012 bind the parties to fund certain development costs, including design, permitting and engineering, as well as to negotiate in good faith 20-year tolling agreements, based on agreed-upon key terms outlined in the commercial development agreements. In May 2013, we signed 20-year liquefaction and regasification tolling capacity agreements with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. which subscribe the full nameplate capacity of the facility. Each tolling agreement is for 4.5 Mtpa of capacity to enable 4.0 Mtpa of LNG export.
In June and November 2013, Sempra Natural Gas signed agreements totaling 1.45 Bcf per day of firm natural gas transportation service to Cameron LNG on the Cameron Interstate Pipeline (subject to effectiveness of the liquefaction and regasification tolling capacity agreements) with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.
On February 11, 2014, the DOE issued an order (Order) granting Cameron LNG, LLC conditional authorization to export from its Cameron liquefaction project approximately 1.7 billion cubic feet per day of domestically produced LNG to countries with which the United States does not have agreements for free trade in natural gas. The conditional authorization granted in the Order is for a term of 20 years commencing on the earlier of the date of first commercial export or seven years from the date of the Order. Under the terms of the Order, Cameron LNG is authorized to export LNG either on its own behalf or as agent for the customers of the project. The authorization is conditional upon receiving a final FERC permit, as we discuss below.
In March 2014, we signed an engineering, procurement and construction contract with a joint venture between CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation. We discuss this contract further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
On April 30, 2014, FERC issued the Final Environmental Impact Statement for the project, which concludes that the project would not result in significant environmental impacts, after taking into account mitigation procedures that will be implemented by Cameron LNG. We now expect to receive the final FERC permit this summer.
RBS Sempra Commodities
In three separate transactions in 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $73 million at March 31, 2014 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 11 of the Notes to Condensed Consolidated Financial Statements herein under “Other Litigation.” In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership. We provide additional information in Notes 4 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.
OTHER SEMPRA ENERGY MATTERS
We discuss proposed Chilean tax reform in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” herein, and the impacts of the 2012 Tax Act, the 2010 Tax Act and the Mexican tax reform legislation passed in December 2013 on our income tax expense, earnings and cash flows in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in the Annual Report.
We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss foreign currency rate risk further under “Foreign Currency Rate Risk” in Item 3. Quantitative and Qualitative Disclosures About Market Risk below. North American natural gas prices, which affect profitability at Sempra Renewables and Sempra Natural Gas, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability. However, management expects that future export capability at Sempra Natural Gas’ Cameron LNG facility would benefit from lower gas prices in North America compared to other regions.
In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.
Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.
LITIGATION
We describe legal proceedings which could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.
We discuss the relevant pronouncements that have recently become effective and have had or may have an impact on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.
We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Annual Report.
INTEREST RATE RISK
The table below shows the nominal amount and the one-year Value at Risk (VaR) for long-term debt at March 31, 2014 and December 31, 2013:
We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.
FOREIGN CURRENCY RATE RISK
We discuss our foreign currency exposure at our Mexican subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations
–
Changes in Revenues, Costs and Earnings
–
Income Taxes
–
Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity” herein. At March 31, 2014, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2013.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective 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 management of each company, including each respective Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.
Under the supervision and with the participation of management, including the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2014, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief Financial Officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.
INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.
On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control – Integrated Framework (2013 Framework). Originally issued in 1992 (1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of March 31, 2014, Sempra Energy, SDG&E and SoCalGas continue to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.
PART II – OTHER INFORMATION
We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 9, 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in “Management's Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Annual Report.
There have not been any material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2013.
The following exhibits relate to each registrant as indicated.
|
SIGNATURES
|
|
|
Sempra Energy:
|
|
|
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.
|
|
|
SEMPRA ENERGY,
(Registrant)
|
|
|
Date: May 2, 2014
|
By: /s/ Trevor I. Mihalik
|
|
Trevor I. Mihalik
Senior Vice President, Controller and
Chief Accounting Officer
|
|
|
San Diego Gas & Electric Company:
|
|
|
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, 2014
|
By: /s/ Robert M. Schlax
|
|
Robert M. Schlax
Vice President, Controller, Chief Financial Officer and Chief Accounting Officer
|
|
|
Southern California Gas Company:
|
|
|
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.
|
|
|
SOUTHERN CALIFORNIA GAS COMPANY,
(Registrant)
|
|
|
Date: May 2, 2014
|
By: /s/ Robert M. Schlax
|
|
Robert M. Schlax
Vice President, Controller, Chief Financial Officer and Chief Accounting Officer
|
|