SEMPRA ENERGY FINANCIAL REPORT TABLE OF CONTENTS | |
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| | Page |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | |
| Our Business | 2 |
| Executive Summary | 9 |
| Business Strategy | 9 |
| Key Events and Issues in 2014 | 10 |
| Results of Operations | 12 |
| Overall Results of Operations of Sempra Energy and Factors Affecting the Results | 12 |
| Segment Results | 15 |
| Changes in Revenues, Costs and Earnings | 21 |
| Book Value Per Share | 40 |
| Capital Resources and Liquidity | 40 |
| Overview | 40 |
| Cash Flows from Operating Activities | 44 |
| Cash Flows from Investing Activities | 47 |
| Cash Flows from Financing Activities | 52 |
| Credit Ratings | 59 |
| Factors Influencing Future Performance | 59 |
| California Utilities | 59 |
| Sempra International | 62 |
| Sempra U.S. Gas & Power | 64 |
| Other Sempra Energy Matters | 69 |
| Litigation | 69 |
| Market Risk | 69 |
| Critical Accounting Policies and Estimates, and Key Noncash Performance Indicators | 73 |
| Information Regarding Forward-Looking Statements | 80 |
| Common Stock Data | 82 |
| Performance Graph – Comparative Total Shareholder Returns | 83 |
| Five-Year Summaries | 84 |
| Controls and Procedures | |
| Evaluation of Disclosure Controls and Procedures | 87 |
| Management’s Report on Internal Control over Financial Reporting | 87 |
| Changes In and Disagreements With Accountants on Accounting and Financial Disclosure | 88 |
| Reports of Independent Registered Public Accounting Firm | 89 |
| Consolidated Financial Statements | |
| Sempra Energy | 95 |
| San Diego Gas & Electric Company | 102 |
| Southern California Gas Company | 109 |
| Notes to Consolidated Financial Statements | 115 |
| Glossary | 240 |
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| This Financial Report is a combined report for the following separate companies (each a separate Securities and Exchange Commission registrant): |
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| Sempra Energy | San Diego Gas & Electric Company | Southern California Gas Company | |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We provide below:
| § | A description of our business |
| § | A discussion and analysis of our operating results for 2012 through 2014 |
| § | Information about our capital resources and liquidity |
| § | Major factors expected to influence our future operating results |
| § | A discussion of market risk affecting our businesses |
| § | A table of accounting policies that we consider critical to our financial condition and results of operations |
You should read Management’s Discussion and Analysis of Financial Condition and Results of Operations in conjunction with the Consolidated Financial Statements and the Notes to Consolidated Financial Statements included in this Annual Report, and in “Risk Factors” contained in our 2014 Annual Report on Form 10-K.
Sempra Energy is a Fortune 500 energy-services holding company whose operating units invest in, develop and operate energy infrastructure, and provide gas and electricity services to their customers in North and South America. 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. (See Figure 1.)
![[a002.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a002.gif)
Figure 1: Sempra Energy’s Operating Units and Reportable Segments
This report includes information for the following separate registrants:
| § | Sempra Energy and its consolidated entities |
References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its 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 1 of the Notes to Consolidated Financial Statements.
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 a population of 3.5 million (1.4 million meters) § Provides natural gas to a population of 3.2 million (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 21.4 million (5.9 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.
SDG&E
SDG&E delivers electricity through 1.4 million meters in San Diego County and an adjacent portion of southern Orange County, California, covering a population of 3.5 million. SDG&E’s electric energy is purchased from others or generated from its own electric generation facilities and, prior to the second quarter of 2012, its 20-percent interest in the San Onofre Nuclear Generating Station (SONGS). Due to operating issues, SONGS was taken offline in the first quarter of 2012, and in June 2013, Southern California Edison Company (Edison), the majority owner and operator of SONGS, made the decision to permanently retire the facility. We discuss the SONGS retirement and related issues in Note 13 of the Notes to Consolidated Financial Statements. SDG&E’s electric generation facilities include Palomar Energy Center, Miramar Energy Center, Desert Star Energy Center and Cuyamaca Peak Energy Plant. SDG&E also delivers natural gas through 0.9 million meters in San Diego County, covering a population of 3.2 million, and transports electricity and natural gas for others. SDG&E’s service territory encompasses 4,100 square miles.
Sempra Energy indirectly owns all of the common stock of SDG&E. SDG&E had publicly held preferred stock that was redeemed in October 2013. We discuss the redemption in Note 11 of the Notes to Consolidated Financial Statements.
SDG&E’s financial statements include a variable interest entity (VIE), Otay Mesa Energy Center LLC (Otay Mesa VIE), of which SDG&E is the primary beneficiary. As we discuss in Note 1 of the Notes to Consolidated Financial Statements under “Variable Interest Entities,” SDG&E has a long-term power purchase agreement with Otay Mesa VIE.
SoCalGas
SoCalGas is the nation’s largest natural gas distribution utility. It owns and operates a natural gas distribution, transmission and storage system that supplies natural gas throughout its approximately 20,000 square miles of service territory. Its service territory extends from San Luis Obispo, California in the north to the Mexican border in the south, excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County. SoCalGas provides natural gas service to residential, commercial, industrial, utility electric generation and wholesale customers through 5.9 million meters, covering a population of 21.4 million.
Sempra Energy indirectly owns all of the common stock of SoCalGas. SoCalGas has publicly held preferred stock. The preferred stock has liquidation preferences totaling $22 million and represents less than 1% of the ordinary voting power of SoCalGas shares.
We provide here descriptions of our Sempra International and Sempra U.S. Gas & Power businesses, primarily operations relating to 2014, 2013 and 2012 earnings. We provide additional information regarding development projects at each of their segments in “Factors Influencing Future Performance” below.
| SEMPRA INTERNATIONAL | | |
| | MARKET | GEOGRAPHIC REGION |
SEMPRA SOUTH AMERICAN UTILITIES Infrastructure supports electric transmission and distribution | § Provides electricity to approximately 2.4 million consumers (approximately 657,000 meters) in Chile and approximately 4.8 million consumers (approximately 1,029,000 meters) 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 |
Sempra International
Sempra South American Utilities
Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and until June 2013, owned interests in utilities in Argentina. We discuss the sale of the two Argentine natural gas utility holding companies in Note 4 of the Notes to Consolidated Financial Statements.
Chilquinta Energía, a wholly owned subsidiary of Sempra South American Utilities, is an electric distribution utility serving approximately 2.4 million consumers through approximately 657,000 meters in the cities of Valparaiso and Viña del Mar in central Chile.
Sempra South American Utilities owns 83.6 percent of Luz del Sur S.A.A. (Luz del Sur), an electric distribution utility that serves approximately 4.8 million consumers through approximately 1,029,000 meters in the southern zone of metropolitan Lima, Peru, and delivers approximately one-third of all power used in the country. The remaining shares of Luz del Sur are held by institutional investors and the general public.
Sempra South American Utilities also owns interests in Tecnored S.A. (Tecnored) in Chile and Tecsur S.A. (Tecsur) in Peru, two energy-services companies that provide electric construction and infrastructure services to Chilquinta Energía and Luz del Sur, as well as third parties. Tecnored also sells electricity to non-regulated customers.
Sempra Mexico
Gas Business
Pipelines. Sempra Mexico develops, owns and operates natural gas transmission pipelines and propane and ethane systems in Mexico. These facilities are contracted under long-term, U.S. dollar-based agreements with Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company), the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE), Shell México Gas Natural (Shell), Gazprom Marketing & Trading Mexico (Gazprom) and other similar counterparties. Its natural gas pipeline systems had a contracted capacity for up to 5,340 million cubic feet (MMcf) per day in 2014.
Sempra Mexico also owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX that develops and operates an ethane pipeline and several natural gas pipelines and propane systems in Mexico.
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 the regulatory accounting requirements of accounting principles generally accepted in the United States of America (U.S. GAAP) record the impact of allowance for funds used during construction (AFUDC) related to equity. Beginning in the fourth quarter of 2013, Sempra Mexico began recording AFUDC equity for its Sonora natural gas pipeline project. Sempra Mexico’s joint venture with PEMEX also began recording AFUDC equity for its Los Ramones I Pipeline project in the fourth quarter of 2013.
LNG. Sempra Mexico’s Energía Costa Azul LNG terminal in Baja California, Mexico is capable of processing 1 billion cubic feet (Bcf) of natural gas per day. The Energía Costa Azul facility generates revenue under capacity services agreements with Shell and Gazprom, expiring in 2028, that permit them, together, to use one-half of the terminal’s capacity.
In connection with Sempra Natural Gas’ LNG purchase agreement with Tangguh PSC Contractors (Tangguh PSC), which we discuss below, Sempra Mexico purchases from Sempra Natural Gas the LNG delivered to Energía Costa Azul by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG to supply a contract through 2022 for the sale of an average of approximately 150 MMcf per day of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the Southern California border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Mexico may purchase natural gas from Sempra Natural Gas’ natural gas marketing operations.
Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas México, S. de R.L. de C.V. (Ecogas), operates in three separate areas in Mexico, and had approximately 106,000 meters (serving more than 400,000 consumers) and sales volume of 65 MMcf per day in 2014.
Power Business
Natural Gas-Fired Generation. Sempra Mexico’s Termoeléctrica de Mexicali, a 625-megawatt (MW) natural gas-fired power plant, is located in Mexicali, Baja California, Mexico. In January 2013, Sempra Mexico’s Termoeléctrica de Mexicali entered into an Energy Management Agreement (EMA), effective January 1, 2012, with our Sempra Natural Gas segment for energy marketing, scheduling and other related services to support its sales of generated power into the California electricity market. Under the EMA, Termoeléctrica de Mexicali pays fees to Sempra Natural Gas for these revenue-generating services. Termoeléctrica de Mexicali also purchases fuel from Sempra Natural Gas. Sempra Mexico records revenue for the sale of power generated by Termoeléctrica de Mexicali, and records cost of sales for the purchases of natural gas and energy management services provided by Sempra Natural Gas.
Wind Power Generation. The Energía Sierra Juárez wind generation project in Baja California is designed to provide up to 1,200 MW of capacity if fully developed. 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 the project, which we expect to be operational in the first half of 2015. In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the first phase of the project to a wholly owned subsidiary of InterGen N.V. We discuss the equity sale further in Note 3 of the Notes to Consolidated Financial Statements.
| SEMPRA U.S. GAS & POWER | | |
| | MARKET | GEOGRAPHIC REGION |
SEMPRA RENEWABLES Develops, owns, operates, or holds interests in renewable energy generation projects | § Wholesale electricity | § U.S.A. |
SEMPRA NATURAL GAS Develops, owns and operates, or holds interests in: § natural gas pipelines and storage facilities § natural gas distribution utilities § a terminal in the U.S. for the import and export of LNG and sale of natural gas § marketing operations § a natural gas-fired electric generation asset (currently held for sale) | § Wholesale electricity § Natural gas § Liquefied natural gas | § U.S.A. |
Sempra U.S. Gas & Power
Sempra Renewables
The following table provides information about the Sempra Renewables wind and solar energy generation facilities that were operational as of December 31, 2014. The generating capacity of these facilities is fully contracted under long-term power purchase agreements (PPA) for the periods indicated in the table.
The majority of Sempra Renewables’ wind farm assets also earn production tax credits (PTC) based on the number of megawatt hours of electricity they generate. A PTC is a federal subsidy that effectively pays wind producers a flat rate for making clean energy and enables wind producers like Sempra Renewables to pass on the benefit to its customers. Because PTCs last for ten years after project completion, any wind turbine that was under construction before the end of 2014 will still earn a full decade of PTCs. For each of the years ended December 31, 2014, 2013 and 2012, PTCs represented a large portion of our wind farm earnings, often exceeding earnings from operations.
| SEMPRA RENEWABLES OPERATING FACILITIES |
| Capacity in Megawatts (MW) at December 31, 2014 |
| Name | Generating capacity | | PPA term in years | First in service | | Location |
| Wholly owned facility: | | | | | | |
| Copper Mountain Solar 1 | 58 | | 20 | 2008 | | Boulder City, Nevada |
| | | | | | | |
Jointly owned facilities(1): | | | | | | |
| Auwahi Wind | 11 | | 20 | 2012 | | Maui, Hawaii |
| Broken Bow 2 Wind | 38 | | 25 | 2014 | | Custer County, Nebraska |
| Cedar Creek 2 Wind | 125 | | 25 | 2011 | | New Raymer, Colorado |
| Flat Ridge 2 Wind | 235 | | 20 and 25 | 2012 | | Wichita, Kansas |
| Fowler Ridge 2 Wind | 100 | | 20 | 2009 | | Benton County, Indiana |
| Mehoopany Wind | 71 | | 20 | 2012 | | Wyoming County, Pennsylvania |
| | Total wind | 580 | | | | | |
| | | | | | | |
| California solar partnership | 55 | | 25 | 2013 | | Tulare and Kings Counties, California |
| Copper Mountain Solar 2 | 46 | | 25 | 2012 | | Boulder City, Nevada |
| Copper Mountain Solar 3 | 92 | (2) | 20 | 2014 | | Boulder City, Nevada |
| Mesquite Solar 1 | 75 | | 20 | 2011 | | Arlington, Arizona |
| | Total solar | 268 | | | | | |
| | | | | | | | |
| | Total MW in operation | 906 | | | | | |
| (1) | Sempra Renewables has a 50-percent interest in each of these facilities and accounts for them as equity method investments. The generating capacity represents Sempra Renewables’ share only. |
| (2) | Total expected generating capacity for Copper Mountain Solar 3 is 250 MW, of which 125 MW is Sempra Renewables’ share. The capacity noted in the above table represents Sempra Renewables’ share of capacity that went into service in 2014; remaining capacity is expected to be in service in 2015. |
The 92-MW first phase of Copper Mountain Solar 2 was placed in service in November 2012, and the 150-MW Mesquite Solar 1 facility went fully into service in December 2012. In the third quarter of 2013, Sempra Renewables sold 50-percent equity interests in these facilities to Consolidated Edison Development (ConEdison Development).
Construction started on Copper Mountain Solar 3 in March 2013, which 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 in 2015. In 2014, 184 MW was placed in service. The cities of Los Angeles and Burbank have contracted for all of the solar power at Copper Mountain Solar 3 for 20 years. In March 2014, we completed the sale of 50 percent of our equity in Copper Mountain Solar 3 to ConEdison Development.
In May 2014, Sempra Renewables acquired a 50-percent ownership interest in four, fully operating solar facilities in California, or the California solar partnership, as we discuss in Note 4 of the Notes to Consolidated Financial Statements.
In October 2014, the 75-MW Broken Bow 2 Wind project achieved commercial operation and, in November 2014, Sempra Renewables sold a 50-percent equity interest in Broken Bow 2 Wind to ConEdison Development.
We discuss the equity sales of these facilities and related matters further in Notes 3 through 5 of the Notes to Consolidated Financial Statements. We discuss capacity under development in “Factors Influencing Future Performance” below.
Sempra Natural Gas
Transportation and Storage. Sempra Natural Gas owns and operates, or holds interests in, natural gas underground storage and related pipeline facilities in Alabama, Louisiana and Mississippi. Sempra Natural Gas provides natural gas marketing, trading and risk management services through the utilization and optimization of contracted natural gas supply, transportation and storage capacity, as well as optimizing its assets in the short-term services market.
Sempra Natural Gas, Tallgrass Energy Partners, L.P. (Tallgrass) and Phillips 66 jointly own, through Rockies Express Pipeline LLC (Rockies Express), the Rockies Express pipeline (REX) that links the Rocky Mountain region to the upper Midwest and the eastern United States. Our ownership interest in the pipeline is 25 percent. Tallgrass purchased its 50-percent equity interest in Rockies Express from Kinder Morgan Energy Partners, L.P. (Kinder Morgan or KMP) in November 2012. Sempra Natural Gas has an agreement through November 2019 with Rockies Express for 200 MMcf per day of capacity on REX, which has a total capacity of 1.8 Bcf per day. Sempra Natural Gas has entered and continues to enter into new capacity release arrangements with other third parties, but these agreements may not be sufficient to offset all of our capacity payments to Rockies Express.
In 2012, we recorded a noncash impairment charge of $239 million after-tax to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the related impairment in Notes 4 and 10 of the Notes to Consolidated Financial Statements.
Distribution. Our Sempra Natural Gas segment owns and operates Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas), regulated natural gas distribution utilities in southwest Alabama and in Mississippi, respectively. Mobile Gas delivers natural gas through approximately 86,000 meters (serving more than 200,000 consumers), and Willmut Gas delivers natural gas through approximately 19,000 meters (serving over 50,000 consumers). Sempra Natural Gas acquired Willmut Gas in May 2012, as we discuss in Note 3 of the Notes to Consolidated Financial Statements.
LNG. The Cameron LNG, LLC (Cameron LNG) regasification terminal in Hackberry, Louisiana, 100-percent owned by Sempra Natural Gas until October 1, 2014, is capable of processing 1.5 Bcf of natural gas per day. The terminal generates revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 MMcf of natural gas per day through 2029. The agreement allows the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term supply agreements to purchase LNG to be received, stored and regasified at the terminal for sale to other parties.
In August 2014, Sempra Energy and its project partners provided their respective final investment decision with regard to the Cameron LNG Holdings, LLC (Cameron LNG Holdings) joint venture for the development, construction and operation of a natural gas liquefaction export facility at the Cameron LNG terminal. Beginning from the October 1, 2014 joint venture effective date, Cameron LNG is no longer wholly owned, and Sempra Natural Gas accounts for its investment in the new joint venture under the equity method.
The liquefaction facility, on which construction began in the second half of 2014, will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States. Cameron LNG Holdings has 20-year liquefaction and regasification tolling capacity agreements in place with GDF SUEZ S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd., that subscribe the full nameplate capacity of the facility. We discuss activities related to the Cameron LNG export project further in “Factors Influencing Future Performance” below and in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
There is a termination agreement in place related to the terminal services agreement discussed above that will result in the termination of the agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG Holdings’ engineering, procurement and construction (EPC) contractor in October 2014, we expect this termination date to occur during the first half of 2017.
Sempra Natural Gas has an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 MMcf of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to Sempra Mexico’s Energía Costa Azul receipt terminal at a price based on the Southern California border index for natural gas. Sempra Natural Gas may also record revenues from non-delivery of cargoes under the provisions of the contract with Tangguh PSC that allow for deliveries to be diverted to other global markets in exchange for cash differential payments.
Generation. Sempra Natural Gas sells electricity under short-term and long-term contracts and into the spot market and other competitive markets. While it may also purchase electricity in the open market to satisfy its contractual obligations, Sempra Natural Gas generally purchases natural gas to fuel its Mesquite Power natural gas-fired power plant, described below, and Sempra Mexico’s Termoeléctrica de Mexicali power plant, described above. The Mesquite Power plant is a 1,250-MW facility located in Arlington, Arizona. In February 2013, Sempra Natural Gas sold one 625-MW block of Mesquite Power to the Salt River Project Agricultural Improvement and Power District for $371 million.
In June 2011, Sempra Natural Gas entered into a 25-year 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, for 240 MW of electricity from the Mesquite Power plant. This contract was amended in early 2013 to increase the capacity to 271 MW. Under the terms of the agreement, Sempra Natural Gas contracted to provide 21 participating SPPR Group members with firm, day-ahead dispatchable power delivered to the Palo Verde hub beginning in January 2015.
In January 2014, management approved a plan to sell the remaining 625-MW block of the Mesquite Power plant. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining block and assign the related SPPR Group contract to the buyer. We anticipate the sale will close in the first half of 2015, subject to obtaining third-party consents for the assignment of the SPPR Group contract to the buyer. We discuss the plan to sell the second 625-MW block of Mesquite Power in Note 3 of the Notes to Consolidated Financial Statements.
Sempra Natural Gas also has various power sale transactions intended to hedge its generation capacity. Through 2014, Sempra Natural Gas sold its power to various counterparties. Sempra Natural Gas has sold certain quantities of expected future generation output under long-term contracts. The remaining output of our natural gas-fired generation facilities, including that of Sempra Mexico’s Termoeléctrica de Mexicali power plant, is available to be sold into energy markets on a day-to-day basis.
In January 2013, Sempra Natural Gas entered into an EMA, effective January 1, 2012, with Sempra Mexico to provide energy marketing, scheduling and other related services to Sempra Mexico’s Termoeléctrica de Mexicali power plant to support its sales of generated power into the California electricity market. We discuss the EMA in “Sempra Mexico – Power Business – Natural Gas-Fired Generation” above.
REGULATION OF OUR UTILITIES
SDG&E and SoCalGas are regulated by federal, state and local governmental agencies. The primary regulatory agency is the California Public Utilities Commission (CPUC). The CPUC regulates the California Utilities’ rates and operations in California, except for SDG&E’s electric transmission operations. The Federal Energy Regulatory Commission (FERC) regulates SDG&E’s electric transmission operations. The FERC also regulates interstate transportation of natural gas and various related matters.
The Nuclear Regulatory Commission (NRC) regulates SONGS, in which SDG&E owns a 20-percent interest. Municipalities and other local authorities may influence decisions affecting the location of utility assets, including natural gas pipelines and electric lines. Some of Sempra Energy’s other operating units are also regulated by the FERC, various state commissions and local governmental entities, and similar authorities in countries other than the United States.
Our South American utilities are regulated by federal and local governmental agencies. The National Energy Commission (Comisión Nacional de Energía, or CNE) regulates Chilquinta Energía in Chile. The Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN) of the National Electricity Office under the Ministry of Energy and Mines regulates Luz del Sur in Peru.
Ecogas, our natural gas distribution utility in northern Mexico, is subject to regulation by the CRE and by the labor and environmental agencies of city, state and federal governments in Mexico.
Mobile Gas, our natural gas distribution utility serving southwest Alabama, is regulated by the Alabama Public Service Commission. Willmut Gas, our natural gas distribution utility serving customers in Hattiesburg, Mississippi, is regulated by the Mississippi Public Service Commission.
BUSINESS STRATEGY
Our focus is to increase shareholder value and meet ever evolving customer needs by sustaining the financial strength, operational flexibility and skilled workforce needed to operate a safe, stable and successful portfolio of integrated energy businesses.
The key components of our strategy include the following three disciplined growth platforms:
| § | South American utilities and Mexican midstream |
| § | U.S. natural gas midstream, including LNG, and renewables |
Operating within these areas, we are focused on generating stable, predictable earnings and cash flows by investing in assets that are primarily regulated or contracted long-term. We have a robust capital program over the next several years and will take a disciplined approach to deploying this capital to areas that fit our strategy and are designed to create shareholder value. By doing so, our goal is to deliver long-term growth that is in excess of what you find in the utility space but with a risk profile in line with our utility peers.
KEY EVENTS AND ISSUES IN 2014
Below are key events and issues that affected our business in 2014; some of these may continue to affect our future results. Each event/issue includes the page number you may reference for additional details.
Major Project Updates:
| § | Sempra Natural Gas’ Joint Venture Formation for Cameron LNG liquefaction project: |
| □ | In September 2014, the U.S. Department of Energy (DOE) granted Cameron LNG final authorization to export domestically produced LNG from its Cameron liquefaction project to countries with which the United States does not have agreements for free trade in natural gas (Non-Free Trade Agreement) (page 67). |
| □ | Between April and July 2014, Cameron LNG received orders from the FERC authorizing the siting, construction and operation of the three-train liquefaction facility, as well as authorization for Cameron Interstate Pipeline’s 21-mile, 42-inch natural gas pipeline expansion, new compressor station and ancillary equipment that will provide natural gas transportation to the Cameron LNG facility (page 68). |
| □ | In August 2014, Sempra Natural Gas and its project partners provided their respective final investment decision for the investment in the joint venture (page 68). |
| □ | Also in August 2014, Sempra Energy and the project partners executed project financing documents, and Sempra Energy entered into completion guarantees related to the financing agreements (page 68). |
| □ | On October 1, 2014, Cameron LNG Holdings, the joint venture partnership among Sempra Energy and three project partners, became effective, and Sempra Natural Gas contributed Cameron LNG to the joint venture (page 68). |
| □ | Later in October 2014, the joint venture issued full notice to proceed to the EPC contractor (page 68). |
| § | Sempra South American Utilities: |
| □ | In October 2014, Luz del Sur received regulatory approval for a $150 million transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima (page 63). |
| § | Sempra Mexico’s IEnova subsidiary: |
| □ | In July 2014, IEnova completed the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. (page 64). |
| □ | Also in July 2014, IEnova’s joint venture with PEMEX and affiliates of PEMEX issued the full notice to proceed with construction of Los Ramones Norte, a natural gas pipeline of approximately 275 miles and two compression stations (page 64). |
| □ | In October 2014, IEnova completed construction of a section of the Sonora pipeline, a 500-mile natural gas pipeline network in northern Mexico (page 63). |
| □ | In December 2014, IEnova’s joint venture with PEMEX completed the 70-mile first phase of the Los Ramones natural gas pipeline (Los Ramones I) (page 63). |
| □ | In December 2014, IEnova was awarded a contract for the development, construction and operation of the approximately 127-mile, 42-inch Ojinaga pipeline, with an estimated cost of $300 million (page 64). |
| □ | In March 2014, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in its 250-MW Copper Mountain Solar 3 solar power facility. A total of 184 MW was placed in service in 2014 (page 7). |
| □ | In May 2014, Sempra Renewables became a 50-percent partner with ConEdison Development in four solar facilities in California (page 149). |
| □ | In July 2014, Sempra Renewables signed a 20-year power sale agreement with Southern California Edison for all of the solar power from the 94-MW Copper Mountain Solar 4 facility beginning in 2020 (page 65). |
| □ | In November 2014, Sempra Renewables sold a 50-percent equity interest to ConEdison Development in the 75-MW Broken Bow 2 Wind project, which went into commercial operation in October 2014 (page 145). |
Other Key Events and Issues:
| □ | In March 2014, the California Independent System Operator (ISO) selected SDG&E to construct the Sycamore-Peñasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Peñasquitos substations (page 219). |
| □ | In May 2014, the FERC approved a multi-party settlement regarding SDG&E’s Electric Transmission Formula Rate filing, establishing among other things, a 10.05 percent rate of return on SDG&E’s electric transmission rate base investment through 2018 (page 219). |
| □ | In June 2014, the CPUC issued a final decision on SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (PSEP), authorizing the proposed decision-making framework and balancing accounts for cost recovery, subject to reasonableness review (page 216). |
| □ | In November 2014, the CPUC issued a final decision approving a settlement agreement, among SDG&E and other settling parties, to the SONGS Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII) (page 209). |
| □ | In November 2014, the California Utilities filed their 2016 General Rate Case (GRC) applications, which included proposed revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements (page 214). |
| □ | In December 2014, the CPUC approved a one-year extension until April 2016 for SDG&E and SoCalGas to file their next Cost of Capital application, maintaining both companies’ current authorized rates of return and capital structure through December 2016 (page 215). |
| § | Sempra South American Utilities: |
| □ | In December 2014, we purchased additional Luz del Sur shares for $74 million, bringing our ownership to 83.6 percent (page 43). |
| § | Sempra U.S. Gas & Power: |
| □ | In April 2014, Rockies Express secured binding financial commitments totaling 1.2 Bcf per day of capacity for a 20-year term for east-to-west transportation services originating at or near Clarington, Ohio, expected to be in service by mid-2015. In June 2014, Rockies Express finished constructing the Seneca Lateral, an initial 0.25 Bcf per day capacity project that connects natural gas production sources in Ohio to REX. The Seneca Lateral capacity was increased to 0.6 Bcf per day in January 2015 (page 66). |
| □ | In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining 625-MW block of the Mesquite Power plant, subject to receipt of required third-party consents. The sale is expected to close in the first half of 2015 (page 66). |
We discuss the following in Results of Operations:
| § | Overall results of our operations and factors affecting those results |
| § | Significant changes in revenues, costs and earnings between periods |
OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY AND FACTORS AFFECTING THE RESULTS
The graphs below show our overall operations from 2010 to 2014.
| OVERALL OPERATIONS OF SEMPRA ENERGY FROM 2010 TO 2014 |
| (Dollars and shares in millions, except per share amounts) |
![[a008.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a008.gif)
![[a004.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a004.gif)
In 2014, our earnings increased by $160 million (16%) to $1.2 billion and our diluted earnings per share increased by $0.62 per share (15%) to $4.63 per share. The net increases in our earnings and diluted earnings per share were primarily impacted by the following increases (decreases), by segment:
SDG&E
| § | $119 million charge in 2013 for loss from plant closure associated with SDG&E’s investment in SONGS, compared to a $(21) million charge in 2014 to adjust the total loss from plant closure, as we discuss in Note 13 of the Notes to Consolidated Financial Statements |
| § | $24 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs |
| § | $15 million favorable resolution of prior years’ income tax items in 2014 compared to a $2 million unfavorable resolution in 2013 |
| § | $(52) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC |
SoCalGas
| § | $24 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC, net of higher non-refundable operating costs |
| § | $(30) million higher income tax expense primarily due to lower favorable resolution of prior years’ income tax items in 2014, higher reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets and lower deductions for self-developed software expenditures |
| § | $(25) million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC |
Sempra South American Utilities
| § | $18 million income tax benefit related to Peru’s recent tax reform, offset by $(6) million income tax expense related to Chilean tax reform |
Sempra Mexico
| § | $30 million favorable impact due to the effects on tax-related balances from foreign currency and inflation |
| § | $24 million higher AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora |
| § | $14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez project in 2014 |
| § | $13 million income tax expense in 2013 due to Mexican tax reform |
| § | $(21) million impact of higher earnings attributable to noncontrolling interests at IEnova ($47 million in 2014 compared to $26 million in 2013) |
Sempra Renewables
| § | $24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind |
| § | $19 million higher deferred income tax benefits, including the benefits from projects placed in service in 2014 and a $5 million reduction of benefits in 2013 as a result of U.S. Treasury grant sequestration |
| § | $(24) million gains in 2013 from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2 |
Sempra Natural Gas
| § | $25 million tax benefit due to the release in 2014 of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments |
| § | $(44) million gain in 2013 on the sale of one 625-MW block of Sempra Natural Gas’ 1,250-MW Mesquite Power natural gas-fired power plant |
Parent and Other
| § | $63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings |
| § | $(38) million income tax expense in 2014 for repatriation of current year foreign earnings |
In 2013 compared to 2012, our earnings increased by $142 million (17%) to $1.0 billion and our diluted earnings per share increased by $0.53 per share (15%) to $4.01 per share. The net increases in our earnings and diluted earnings per share were primarily impacted by the following increases (decreases), by segment:
SDG&E
| § | $61 million higher earnings from CPUC base operations and electric transmission, including Sunrise Powerlink |
| § | $52 million favorable impact on 2013 earnings from the retroactive impact for 2012 of the 2012 GRC, for which a final decision by the CPUC was issued in the second quarter of 2013 |
| § | $(119) million charge for loss from plant closure associated with SDG&E’s investment in the SONGS nuclear facility |
| § | $(54) million from an income tax benefit recorded in 2012 related to a change in the income tax treatment of certain repairs expenditures, the lower rate of return authorized in our CPUC cost of capital proceeding and higher interest expense |
SoCalGas
| § | $51 million higher operating margin and newly recovered costs as a result of the 2012 GRC |
| § | $25 million favorable impact on 2013 earnings from the retroactive impact for 2012 of the 2012 GRC |
Sempra Mexico
| § | $(26) 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 its common stock |
Sempra Renewables
| § | $24 million gains from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2 in 2013 |
| § | $(50) million lower deferred income tax benefits, including $5 million decrease from U.S. Treasury grant sequestration in 2013, as a result of wind and solar generating assets placed in service in 2012 |
Sempra Natural Gas
| § | $239 million in noncash impairment charges in 2012 to write down our investment in Rockies Express, partially offset by a $25 million income tax make-whole payment received in 2012 from Kinder Morgan |
| § | $44 million gain on the sale of one 625-MW block of Sempra Natural Gas’ 1,250-MW Mesquite Power natural gas-fired power plant in the first quarter of 2013 |
| § | $41 million higher earnings from LNG operations, primarily due to lower of cost or market adjustments in 2012 associated with the timing of cargoes, the impact of higher natural gas prices on marketing operations and lower costs resulting from commercial arrangements entered into with affiliates |
Parent and Other
| § | $(63) million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings |
| § | $(54) million income tax benefit in 2012 primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term |
Diluted earnings per share for 2013 compared to 2012 were also impacted by an increase in the number of shares outstanding (decrease of $0.05 per share).
The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”
| SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT 2012-2014 |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| California Utilities: | | | | | | | | | | | | |
| SDG&E(1) | $ | 507 | 44 | % | $ | 404 | 41 | % | $ | 484 | 56 | % |
| SoCalGas(2) | | 332 | 29 | | | 364 | 37 | | | 289 | 34 | |
| Sempra International: | | | | | | | | | | | | |
| Sempra South American Utilities | | 172 | 15 | | | 153 | 15 | | | 164 | 19 | |
| Sempra Mexico | | 192 | 16 | | | 122 | 12 | | | 157 | 18 | |
| Sempra U.S. Gas & Power: | | | | | | | | | | | | |
| Sempra Renewables | | 81 | 7 | | | 62 | 6 | | | 61 | 7 | |
| Sempra Natural Gas | | 50 | 4 | | | 64 | 6 | | | (241) | (28) | |
| Parent and other(3) | | (173) | (15) | | | (168) | (17) | | | (55) | (6) | |
| Earnings | $ | 1,161 | 100 | % | $ | 1,001 | 100 | % | $ | 859 | 100 | % |
| (1) | For 2013, amount is after preferred dividends and call premium on preferred stock. For 2012, amount is after preferred dividends. |
| (2) | After preferred dividends. |
| (3) | Includes after-tax interest expense ($144 million in each of 2014 and 2013 and $150 million in 2012), intercompany eliminations recorded in consolidation and certain corporate costs. |
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) |
![[a010.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a010.gif)
SDG&E
Our SDG&E segment recorded earnings of:
| § | $404 million in 2013 ($411 million before preferred dividends and call premium) |
| § | $484 million in 2012 ($489 million before preferred dividends) |
The increase in earnings of $103 million (25%) in 2014 was primarily due to:
| § | $119 million charge in 2013 for loss from plant closure associated with SDG&E’s investment in SONGS, compared to a $21 million charge in 2014 to adjust the total loss from plant closure, as we discuss in Note 13 of the Notes to Consolidated Financial Statements; |
| § | $24 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC and lower non-refundable operating costs; |
| § | $15 million favorable resolution of prior years’ income tax items in 2014 compared to a $2 million unfavorable resolution in 2013; and |
| § | $3 million lower legal costs in 2014; offset by |
| § | $52 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; and |
| § | $7 million lower earnings from electric transmission operations primarily due to lower FERC-authorized return on equity. |
The decrease of $80 million (17%) in 2013 compared to 2012 was primarily due to:
| § | $119 million charge for loss from plant closure associated with SDG&E’s investment in SONGS; |
| § | $22 million income tax benefit recorded in the third quarter of 2012 for full-year 2011 from the change in the income tax treatment of certain repairs expenditures, as we discuss below in “Income Taxes;” |
| § | $20 million lower CPUC-authorized rate of return established in the CPUC cost of capital proceeding effective as of January 1, 2013; |
| § | $12 million higher interest expense; |
| § | $11 million loss of revenue from SONGS due to the early closure of the plant; and |
| § | $6 million for the recovery from the DOE in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel; offset by |
| § | $52 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; |
| § | $38 million higher CPUC base operating margin as a result of the final 2012 GRC decision, net of operating costs; and |
| § | $23 million higher electric transmission margin. |
SoCalGas
Our SoCalGas segment recorded earnings of:
| § | $332 million in 2014 ($333 million before preferred dividends) |
| § | $364 million in 2013 ($365 million before preferred dividends) |
| § | $289 million in 2012 ($290 million before preferred dividends) |
The decrease in earnings of $32 million (9%) in 2014 was primarily due to:
| § | $25 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; |
| § | $15 million lower favorable resolution of prior years’ income tax items in 2014; |
| § | $15 million increase in income tax expense primarily due to higher reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets, and from lower deductions for self-developed software expenditures; |
| § | $5 million write-off in 2014 of certain costs incurred associated with the PSEP that were disallowed for recovery in the final PSEP decision (as we discuss in Note 14 of the Notes to Consolidated Financial Statements); and |
| § | $4 million insurance recovery in 2013 of previously expensed costs; offset by |
| § | $24 million higher CPUC base operating margin authorized for 2014 in the 2012 GRC, net of higher non-refundable operating costs; and |
| § | $9 million from an increase in AFUDC related to equity. |
The increase of $75 million (26%) in 2013 compared to 2012 was primarily due to:
| § | $36 million higher CPUC base operating margin as a result of the final 2012 GRC decision and lower non-refundable operating costs; |
| § | $25 million favorable impact on 2013 earnings from the retroactive application for 2012 of the final decision in the 2012 GRC; |
| § | $20 million higher favorable resolution of prior years’ income tax issues in 2013; and |
| § | $15 million due to costs associated with the Transmission Integrity Management Program (TIMP) being expensed in 2012 now being fully recovered (balanced) in revenues pursuant to the 2012 GRC; offset by |
| § | $14 million lower CPUC-authorized rate of return established in the CPUC cost of capital proceeding effective as of January 1, 2013. |
| EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL |
| (Dollars in millions) |
![[a011.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a011.gif)
Sempra South American Utilities
Our Sempra South American Utilities segment recorded earnings of:
The increase in earnings of $19 million (12%) in 2014 was primarily due to:
| § | $18 million income tax benefit related to Peru’s recent tax reform, offset by $6 million income tax expense related to Chilean tax reform as we discuss below under “Income Taxes – Tax Reform;” |
| § | $12 million higher earnings associated with the relocation of electrical infrastructure projects; |
| § | $11 million equity losses in 2013 related to the sale of our investments in two Argentine natural gas utility holding companies; and |
| § | $10 million higher earnings from operations mainly due to an increase in volume, primarily from customer growth; offset by |
| § | $16 million lower earnings from foreign currency effects; |
| § | $33 million earnings attributable to noncontrolling interests in 2014 compared to $28 million in 2013; and |
| § | $5 million higher interest expense mainly in Chile related to the inflationary effect on local bonds. |
The decrease in earnings of $11 million (7%) in 2013 compared to 2012 was primarily due to:
| § | $11 million equity losses related to our investments in two Argentine natural gas utility holding companies that were sold in 2013; and |
| § | $4 million equity losses from our joint venture in Chile in 2013 resulting from a forward exchange contract to manage foreign currency exchange rate risk; offset by |
| § | $4 million lower income tax expense from an unfavorable resolution of prior years’ tax matters in 2012. |
Sempra Mexico
Sempra Mexico recorded earnings of:
| | The increase in earnings of $70 million (57%) in 2014 was primarily due to: |
| § | $30 million favorable impact ($29 million benefit in 2014 and $1 million expense in 2013) primarily due to the effects on tax-related balances from foreign currency and inflation; |
| § | $24 million higher earnings from operations mainly due to prior year’s scheduled major maintenance and improved results at our Mexicali power plant, and start of operations of a section of the Sonora pipeline; |
| § | $24 million higher AFUDC in 2014 related to equity associated with construction of the natural gas pipeline in Sonora; |
| § | $14 million gain from the sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind project in July 2014; and |
| § | $13 million income tax expense in 2013 due to Mexican tax reform; offset by |
| § | $47 million earnings attributable to noncontrolling interests at IEnova in 2014 compared to $26 million in 2013; and |
| § | $15 million unfavorable translation effect primarily on Peso-denominated receivables. |
The decrease of $35 million (22%) in 2013 compared to 2012 was primarily due to:
| § | $26 million decrease in Sempra Mexico’s earnings for earnings attributable to noncontrolling interests at IEnova following its stock offerings in March 2013; |
| § | $13 million increase in deferred income tax liability due to Mexico income tax law enacted in the fourth quarter of 2013 and effective January 1, 2014, as we discuss below in “Income Taxes;” |
| § | $10 million lower earnings mainly due to administrative expenses related to the new IEnova public company structure, scheduled plant maintenance at our Mexicali power plant in 2013, and the net impact of changes in affiliate agreements; |
| § | $7 million negative translation effect primarily on Peso-denominated tax receivables; and |
| § | $6 million higher interest expense, including interest associated with the IEnova debt offering in February 2013; offset by |
| § | $19 million AFUDC related to equity associated with construction of the natural gas pipeline in Sonora; and |
| § | $7 million lower income tax expense, including the favorable impact of Mexican currency inflation and translation adjustments in 2013 compared to 2012. |
| EARNINGS (LOSSES) BY SEGMENT – SEMPRA U.S. GAS & POWER |
| (Dollars in millions) |
![[a012.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/a012.gif)
Sempra Renewables
Sempra Renewables recorded earnings of:
The increase in earnings of $19 million (31%) in 2014 was primarily due to:
| § | $24 million gains in 2014 from the sale of 50-percent equity interests in Copper Mountain Solar 3 and Broken Bow 2 Wind; and |
| § | $19 million higher deferred income tax benefits, including the benefits of projects placed in service in 2014 and a $5 million reduction of benefits in 2013 as a result of U.S. Treasury grant sequestration; offset by |
| § | $24 million gains in 2013 from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2. |
The increase in earnings of $1 million (2%) in 2013 compared to 2012 was primarily due to:
| § | $24 million gains in 2013 from the sale of 50-percent equity interests in Mesquite Solar 1 and Copper Mountain Solar 2; |
| § | $16 million higher earnings attributable to our wind assets; and |
| § | $13 million higher earnings from our solar assets, including $6 million from interest rate hedges; offset by |
| § | $50 million lower deferred income tax benefits, including $5 million decrease from U.S. Treasury grant sequestration in 2013, as a result of solar and wind generating assets placed in service in 2012. |
Sempra Natural Gas
Sempra Natural Gas recorded earnings (losses) of:
The decrease in earnings of $14 million (22%) in 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 |
| § | $15 million lower results from gas storage operations and natural gas marketing activities; offset by |
| § | $25 million tax benefit due to the release in 2014 of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments; |
| § | $10 million lower operating costs at the Mesquite Power plant, primarily depreciation due to the classification of the remaining 625-MW block as an asset held for sale; and |
| § | $9 million higher net intercompany interest income. |
The change in 2013 compared to 2012 was primarily due to:
| § | $239 million write-down of our investment in Rockies Express in 2012; |
| § | $44 million gain in 2013 on the sale of a 625-MW block of the Mesquite Power plant, net of related expenses; |
| § | $41 million higher earnings from LNG operations, primarily due to lower of cost or market adjustments in 2012 associated with the timing of cargoes, the impact of higher natural gas prices on marketing operations and lower costs resulting from commercial arrangements entered into with affiliates; |
| § | $11 million lower interest expense and operating costs at the Mesquite Power plant due to the sale of one block of the plant in the first quarter of 2013; and |
| § | $10 million improved results at our marketing and storage operations primarily driven by sales of natural gas in 2013; offset by |
| § | a $25 million payment received from Kinder Morgan in 2012 due to tax impacts related to the sale of their interest in Rockies Express; and |
| § | $12 million lower earnings due to capacity release contracts related to Rockies Express that expired in 2013. |
Parent and Other
Losses for Parent and Other were
The increase in losses of $5 million (3%) in 2014 was primarily due to:
| § | $38 million income tax expense in 2014 from the repatriation of current year foreign earnings; |
| § | $9 million lower investment net gains on dedicated assets in support of our executive retirement and deferred compensation plans; |
| § | $9 million higher net interest expense; and |
| § | $8 million lower income tax benefits in 2014, excluding income tax items discussed separately; offset by |
| § | $63 million income tax expense in 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. |
The increase in losses of $113 million in 2013 compared to 2012 was primarily due to:
| § | $63 million income tax expense resulting from a corporate reorganization in connection with the IEnova stock offerings; |
| § | $54 million income tax benefit in 2012 primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term, as we discuss below in “Income Taxes;” and |
| § | $42 million higher net interest expense primarily due to lower intercompany interest income from a debt restructuring at Sempra Natural Gas and increased borrowings from Sempra Renewables; offset by |
| § | $42 million higher income tax benefits, excluding income tax items discussed above, primarily due to higher favorable resolution of prior years’ income tax issues and the timing of a change in tax law. We discuss this law, the American Taxpayer Relief Act of 2012, in “Income Taxes” below. |
CHANGES IN REVENUES, COSTS AND EARNINGS
This section contains a discussion of the differences between periods in the specific line items of the Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.
Utilities Revenues
Our utilities revenues include
Natural gas revenues at:
| § | 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:
| § | 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 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.
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 2012-2014 |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Electric revenues: | | | | | | |
| SDG&E | $ | 3,785 | $ | 3,537 | $ | 3,226 |
| Sempra South American Utilities | | 1,434 | | 1,383 | | 1,349 |
| Eliminations and adjustments | | (10) | | (9) | | (7) |
| | Total | | 5,209 | | 4,911 | | 4,568 |
| Natural gas revenues: | | | | | | |
| SoCalGas | | 3,855 | | 3,736 | | 3,282 |
| SDG&E | | 544 | | 529 | | 468 |
| Sempra Mexico | | 109 | | 97 | | 75 |
| Sempra Natural Gas | | 113 | | 109 | | 96 |
| Eliminations and adjustments | | (72) | | (73) | | (48) |
| | Total | | 4,549 | | 4,398 | | 3,873 |
| Total utilities revenues | $ | 9,758 | $ | 9,309 | $ | 8,441 |
| Cost of electric fuel and purchased power: | | | | | | |
| SDG&E | $ | 1,309 | $ | 1,019 | $ | 892 |
| Sempra South American Utilities | | 972 | | 913 | | 868 |
| | Total | $ | 2,281 | $ | 1,932 | $ | 1,760 |
| Cost of natural gas: | | | | | | |
| SoCalGas | $ | 1,449 | $ | 1,362 | $ | 1,074 |
| SDG&E | | 208 | | 204 | | 151 |
| Sempra Mexico | | 74 | | 63 | | 45 |
| Sempra Natural Gas | | 44 | | 35 | | 25 |
| Eliminations and adjustments | | (17) | | (18) | | (5) |
| | Total | $ | 1,758 | $ | 1,646 | $ | 1,290 |
Sempra Energy Consolidated
Electric Revenues
Our electric revenues increased by $298 million (6%) to $5.2 billion in 2014 primarily due to:
| § | $248 million increase at SDG&E, including: |
| □ | $290 million increase in cost of electric fuel and purchased power, which we discuss below, |
| □ | $39 million increase in authorized revenues from 2014 attrition, and |
| □ | $32 million higher authorized revenues from electric transmission, offset by |
| □ | $61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012, and |
| □ | $47 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and |
| § | $51 million increase at our South American utilities primarily due to higher rates and volumes at both Luz del Sur and Chilquinta Energía, offset by foreign currency exchange rate effects. |
In 2013 compared to 2012, our electric revenues increased by $343 million (8%) to $4.9 billion primarily due to:
| § | $311 million increase at SDG&E, including: |
| □ | $140 million higher authorized revenues from electric transmission, |
| □ | $127 million increase in cost of electric fuel and purchased power, which we discuss below, |
| □ | $94 million higher authorized revenue from implementation of the 2012 GRC decision and 2013 attrition. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, 2012 authorized revenue was essentially unchanged from the 2011 authorized revenue, and |
| □ | $61 million increase due to the retroactive application in 2013 of the 2012 GRC decision for the period from January 2012 through December 2012, offset by |
| □ | $40 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses, |
| □ | $33 million loss of revenue from SONGS due to the early closure of the plant, and |
| □ | $30 million lower CPUC-authorized rate of return established in the CPUC cost of capital proceeding effective as of January 1, 2013; and |
| § | $34 million increase at our South American utilities primarily due to higher volumes, net of foreign currency exchange rate effects. |
Our utilities’ cost of electric fuel and purchased power increased by $349 million (18%) to $2.3 billion in 2014 primarily due to:
| § | $290 million increase at SDG&E, which we discuss below; and |
| § | $59 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. |
Our utilities’ cost of electric fuel and purchased power increased by $172 million (10%) to $1.9 billion in 2013 compared to 2012 primarily due to:
| § | $127 million increase in SDG&E’s 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, slightly offset by lower demand driven by an overall cooler summer in 2013 compared to 2012; and |
| § | $45 million increase at our South American utilities driven primarily by higher volumes and higher costs of purchased power, net of 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
In 2014, Sempra Energy’s natural gas revenues increased by $151 million (3%) to $4.5 billion, and the cost of natural gas increased by $112 million (7%) to $1.8 billion. The increase in natural gas revenues included
| § | increases in cost of natural gas sold at both SoCalGas and SDG&E, as we discuss below; |
| § | increases of $52 million and $8 million at SoCalGas and SDG&E, respectively, in authorized revenues from 2014 attrition; and |
| § | $30 million higher revenues from the advanced metering infrastructure project at SoCalGas; offset by |
| § | $30 million favorable impact on the California Utilities’ 2013 revenues from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012; and |
| § | $18 million lower recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses. |
In 2013 compared to 2012, Sempra Energy’s natural gas revenues increased by $525 million (14%) to $4.4 billion, and the cost of natural gas increased by $356 million (28%) to $1.6 billion. The increase in natural gas revenues included
| § | an increase in cost of natural gas sold at both SoCalGas and SDG&E, as we discuss below; |
| § | increases of $64 million and $20 million at SoCalGas and SDG&E, respectively, primarily due to higher authorized revenues from implementation of the 2012 GRC decision and 2013 attrition. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, 2012 authorized revenue was essentially unchanged from the 2011 authorized revenue; |
| § | higher recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; and |
| § | $30 million increase due to the retroactive application in 2013 of the 2012 GRC decision for the period from January 2012 through December 2012. |
We discuss the changes in revenues and 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.
| SDG&E |
| ELECTRIC DISTRIBUTION AND TRANSMISSION 2012-2014 |
| (Volumes in millions of kilowatt-hours, dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Customer class | Volumes | Revenue | Volumes | Revenue | Volumes | Revenue |
| Residential | 7,338 | $ | 1,370 | 7,392 | $ | 1,283 | 7,587 | $ | 1,242 |
| Commercial | 6,974 | | 1,418 | 6,722 | | 1,080 | 6,902 | | 1,017 |
| Industrial | 2,067 | | 342 | 1,962 | | 257 | 2,042 | | 249 |
| Direct access(1) | 3,648 | | 205 | 3,593 | | 151 | 3,399 | | 148 |
| Street and highway lighting | 88 | | 15 | 87 | | 12 | 95 | | 13 |
| | | 20,115 | | 3,350 | 19,756 | | 2,783 | 20,025 | | 2,669 |
| CAISO shared transmission revenue - net(2) | | | 162 | | | 268 | | | 64 |
| Other revenues | | | 205 | | | 172 | | | 134 |
| Balancing accounts | | | 68 | | | 314 | | | 359 |
| Total(3) | | $ | 3,785 | | $ | 3,537 | | $ | 3,226 |
| (1) | The Direct Access (DA) program, which offered all customers the option to purchase their electric commodity services from a third-party Energy Service Provider (ESP) instead of continuing to receive these services from SDG&E, was implemented in 1998 and suspended in 2001. In 2009, Senate Bill 695 required the CPUC to develop a process and rules for a limited re-opening of DA to be phased in over a period of time. In 2010, the CPUC adopted the process and rules for the limited re-opening of DA for non-residential customers under a 4-year phase-in schedule. The 2013 tranche of non-residential customers switching to DA resulted in higher volumes in 2013. The increase in revenues from the higher volumes was offset by lower tariffs in 2013 compared to 2012. The phase-in program ended in 2013. Tariffs in 2014 increased from 2013. |
| (2) | California Independent System Operator (CAISO). CAISO shared transmission revenue changes in 2014 are primarily due to timing differences between billed amounts and recorded or authorized costs, which are offset by corresponding changes in balancing accounts. Shared transmission revenue increased in 2013 compared to 2012 due to the Sunrise Powerlink transmission line being placed in service in June 2012. |
| (3) | Includes sales to affiliates of $10 million in 2014, $9 million in 2013 and $7 million in 2012. |
SDG&E’s electric revenues increased by $248 million (7%) to $3.8 billion in 2014 primarily due to:
| § | $290 million increase in cost of electric fuel and purchased power, including: |
| □ | an increase in purchased power primarily due to the incremental purchase of renewable energy at higher prices, offset by |
| □ | a decrease in cost of electric fuel primarily due to planned outages at SDG&E-owned generation facilities; |
| § | $39 million increase in authorized revenues from 2014 attrition; and |
| § | $32 million higher authorized revenues from electric transmission; offset by |
| § | $61 million favorable impact on 2013 revenues from the retroactive application of the 2012 GRC decision for the period from January 2012 through December 2012; and |
| § | $47 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses. |
In 2013 compared to 2012, electric revenues increased by $311 million (10%) to $3.5 billion at SDG&E, primarily due to:
| § | $140 million higher authorized revenues from electric transmission including: |
| □ | $80 million from placing the Sunrise Powerlink transmission line in service in June 2012, and |
| □ | $60 million from increased investment in other transmission assets; |
| § | $127 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, slightly offset by lower demand driven by an overall cooler summer in 2013 compared to 2012; |
| § | $94 million higher authorized revenue from implementation of the 2012 GRC decision and 2013 attrition. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SDG&E’s 2012 authorized revenue was essentially unchanged from the 2011 authorized revenue; and |
| § | $61 million increase due to the retroactive application in 2013 of the 2012 GRC decision for the period from January 2012 through December 2012; offset by |
| § | $40 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; |
| § | $33 million loss of revenue from SONGS due to the early closure of the plant; and |
| § | $30 million lower CPUC-authorized rate of return established in the CPUC cost of capital proceeding effective as of January 1, 2013. |
We do not include in the Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts in 2013 and 2012 that were allocated to SDG&E by the California Department of Water Resources (DWR). However, we do include the associated volumes and distribution revenues in the table above. The related operating agreement with the DWR expired at the end of 2013.
SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas
The following tables 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.
| SDG&E |
| NATURAL GAS SALES AND TRANSPORTATION 2012-2014 |
| (Volumes in billion cubic feet, dollars in millions) |
| | Natural Gas Sales | Transportation | Total |
| Customer class | Volumes | Revenue | Volumes | Revenue | Volumes | Revenue |
| 2014: | | | | | | | | | |
| Residential | 25 | $ | 304 | ― | $ | 2 | 25 | $ | 306 |
| Commercial and industrial | 14 | | 106 | 8 | | 10 | 22 | | 116 |
| Electric generation plants(1) | ― | | ― | 26 | | 2 | 26 | | 2 |
| | 39 | $ | 410 | 34 | $ | 14 | 73 | | 424 |
| Other revenues | | | | | | | | | 40 |
| Balancing accounts | | | | | | | | | 80 |
| Total(2) | | | | | | | | $ | 544 |
| 2013: | | | | | | | | | |
| Residential | 31 | $ | 323 | ― | $ | 1 | 31 | $ | 324 |
| Commercial and industrial | 15 | | 98 | 9 | | 13 | 24 | | 111 |
| Electric generation plants | ― | | ― | 25 | | 15 | 25 | | 15 |
| | 46 | $ | 421 | 34 | $ | 29 | 80 | | 450 |
| Other revenues | | | | | | | | | 42 |
| Balancing accounts | | | | | | | | | 37 |
| Total(2) | | | | | | | | $ | 529 |
| 2012: | | | | | | | | | |
| Residential | 30 | $ | 266 | ― | $ | 1 | 30 | $ | 267 |
| Commercial and industrial | 15 | | 76 | 8 | | 11 | 23 | | 87 |
| Electric generation plants | ― | | ― | 37 | | 15 | 37 | | 15 |
| | 45 | $ | 342 | 45 | $ | 27 | 90 | | 369 |
| Other revenues | | | | | | | | | 40 |
| Balancing accounts | | | | | | | | | 59 |
| Total(2) | | | | | | | | $ | 468 |
| (1) Lower electric generation plants revenue in 2014 compared to 2013 is due to refunds of previous overcollections to adjust forecasted rates to actual. |
| (2) Includes sales to affiliates of $3 million in both 2014 and 2013 and $2 million in 2012. |
In 2014, SDG&E’s natural gas revenues increased by $15 million (3%) to $544 million, and the cost of natural gas increased by $4 million (2%) to $208 million. The increase in revenues was primarily due to:
| § | higher cost of natural gas sold, offset by lower volumes, as we discuss below; and |
| § | $8 million increase in authorized revenues from 2014 attrition; offset by |
| § | $5 million favorable impact from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012. |
In 2013 compared to 2012, SDG&E’s natural gas revenues increased by $61 million (13%) to $529 million, and the cost of natural gas increased by $53 million (35%) to $204 million. The increase in revenues was primarily due to:
| § | higher cost of natural gas sold, as we discuss below; |
| § | $20 million higher authorized revenue from implementation of the 2012 GRC decision and 2013 attrition. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SDG&E’s 2012 authorized revenue was essentially unchanged from the 2011 authorized revenue; and |
| § | $5 million increase from the retroactive application in 2013 of the 2012 GRC decision for the period from January 2012 through December 2012; offset by |
| § | $5 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses. |
SDG&E’s average cost of natural gas was $5.44 per thousand cubic feet (Mcf) for 2014, $4.49 per Mcf for 2013 and $3.62 per Mcf for 2012. In 2014, the 21-percent increase of $0.95 per Mcf resulted in higher revenues and cost of $36 million compared to 2013. 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 $32 million.
In 2013, the 24-percent increase of $0.87 per Mcf resulted in higher revenues and cost of $40 million compared to 2012.
| SOCALGAS |
| NATURAL GAS SALES AND TRANSPORTATION 2012-2014 |
| (Volumes in billion cubic feet, dollars in millions) |
| | Natural Gas Sales | Transportation | Total |
| Customer class | Volumes | Revenue | Volumes | Revenue | Volumes | Revenue |
| 2014: | | | | | | | | | |
| Residential | 195 | $ | 2,170 | 3 | $ | 16 | 198 | $ | 2,186 |
| Commercial and industrial | 92 | | 743 | 293 | | 260 | 385 | | 1,003 |
| Electric generation plants | ― | | ― | 211 | | 42 | 211 | | 42 |
| Wholesale | ― | | ― | 150 | | 24 | 150 | | 24 |
| | 287 | $ | 2,913 | 657 | $ | 342 | 944 | | 3,255 |
| Other revenues | | | | | | | | | 103 |
| Balancing accounts | | | | | | | | | 497 |
| Total(1) | | | | | | | | $ | 3,855 |
| 2013: | | | | | | | | | |
| Residential | 234 | $ | 2,204 | 2 | $ | 8 | 236 | $ | 2,212 |
| Commercial and industrial | 100 | | 691 | 293 | | 242 | 393 | | 933 |
| Electric generation plants | ― | | ― | 200 | | 44 | 200 | | 44 |
| Wholesale | ― | | ― | 170 | | 27 | 170 | | 27 |
| | 334 | $ | 2,895 | 665 | $ | 321 | 999 | | 3,216 |
| Other revenues | | | | | | | | | 101 |
| Balancing accounts | | | | | | | | | 419 |
| Total(1) | | | | | | | | $ | 3,736 |
| 2012: | | | | | | | | | |
| Residential | 234 | $ | 1,963 | 2 | $ | 8 | 236 | $ | 1,971 |
| Commercial and industrial | 101 | | 608 | 283 | | 240 | 384 | | 848 |
| Electric generation plants | ― | | ― | 231 | | 39 | 231 | | 39 |
| Wholesale | ― | | ― | 175 | | 24 | 175 | | 24 |
| | 335 | $ | 2,571 | 691 | $ | 311 | 1,026 | | 2,882 |
| Other revenues | | | | | | | | | 91 |
| Balancing accounts | | | | | | | | | 309 |
| Total(1) | | | | | | | | $ | 3,282 |
| (1) Includes sales to affiliates of $69 million in 2014, $70 million in 2013 and $46 million in 2012. |
In 2014, SoCalGas’ natural gas revenues increased by $119 million (3%) to $3.9 billion, and the cost of natural gas increased by $87 million (6%) to $1.4 billion. The revenue increase included
| § | an increase in the market price of natural gas purchased, offset by lower volumes, as we discuss below; |
| § | $52 million increase in authorized revenues from 2014 attrition; and |
| § | $30 million higher revenues from the advanced metering infrastructure project; offset by |
| § | $25 million favorable impact from the retroactive application of the 2012 GRC decision, recorded in the second quarter of 2013, for the period from January 2012 through December 2012; and |
| § | $18 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses. |
In 2013 compared to 2012, SoCalGas’ natural gas revenues increased by $454 million (14%) to $3.7 billion, and the cost of natural gas increased by $288 million (27%) to $1.4 billion. The revenue increase included
| § | an increase in cost of natural gas sold from higher natural gas prices, as we discuss below; |
| § | $76 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses; |
| § | $64 million increase primarily due to higher authorized revenue from implementation of the 2012 GRC decision and 2013 attrition. Due to the delay in the issuance of the 2012 GRC decision by the CPUC, SoCalGas’ 2012 authorized revenue was essentially unchanged from the 2011 authorized revenue; and |
| § | $25 million increase due to the retroactive application in 2013 of the 2012 GRC decision for the period from January 2012 through December 2012. |
SoCalGas’ average cost of natural gas was $5.06 per Mcf for 2014, $4.08 per Mcf for 2013 and $3.21 per Mcf for 2012. In 2014, the 24-percent increase of $0.98 per Mcf resulted in higher revenues and cost of $280 million compared to 2013. 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 $193 million.
In 2013, the 27-percent increase of $0.87 per Mcf resulted in higher revenues and cost of $291 million compared to 2012.
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 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.
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 revenue for our utilities outside of California:
| OTHER UTILITIES |
| NATURAL GAS AND ELECTRIC REVENUES 2012-2014 |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| | | Volumes | Revenue | Volumes | Revenue | Volumes | Revenue |
| Natural Gas Sales (billion cubic feet): | | | | | | | | | |
| Sempra Mexico - Ecogas | 24 | $ | 109 | 24 | $ | 97 | 23 | $ | 75 |
| Sempra Natural Gas: | | | | | | | | | |
| Mobile Gas | 38 | | 89 | 40 | | 88 | 43 | | 86 |
| Willmut Gas(1) | 3 | | 24 | 3 | | 21 | 1 | | 10 |
| Total | 65 | $ | 222 | 67 | $ | 206 | 67 | $ | 171 |
| | | | | | | | | | | |
| Electric Sales (million kilowatt hours): | | | | | | | | | |
| Sempra South American Utilities: | | | | | | | | | |
| Luz del Sur | 7,287 | $ | 854 | 6,984 | $ | 785 | 6,668 | $ | 759 |
| Chilquinta Energía | 2,944 | | 530 | 2,856 | | 537 | 2,698 | | 533 |
| | | 10,231 | | 1,384 | 9,840 | | 1,322 | 9,366 | | 1,292 |
| Other service revenues | | | 50 | | | 61 | | | 57 |
| Total | | $ | 1,434 | | $ | 1,383 | | $ | 1,349 |
| (1) | We acquired Willmut Gas in May 2012. |
| | |
Energy-Related Businesses: Revenues and Cost of Sales
The table below shows revenues and cost of sales for our energy-related businesses.
| ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES 2012-2014 |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| REVENUES | | | | | | | | | | | | |
| Sempra South American Utilities | $ | 100 | 8 | % | $ | 112 | 9 | % | $ | 92 | 8 | % |
| Sempra Mexico | | 709 | 55 | | | 578 | 46 | | | 530 | 44 | |
| Sempra Renewables | | 35 | 3 | | | 82 | 7 | | | 68 | 6 | |
| Sempra Natural Gas | | 866 | 68 | | | 799 | 64 | | | 835 | 69 | |
| Intersegment revenues, adjustments | | | | | | | | | | | | |
| and eliminations(1) | | (433) | (34) | | | (323) | (26) | | | (319) | (27) | |
| Total revenues | $ | 1,277 | 100 | % | $ | 1,248 | 100 | % | $ | 1,206 | 100 | % |
| COST OF SALES(2) | | | | | | | | | | | | |
| Sempra South American Utilities | $ | 11 | 2 | % | $ | ― | ― | % | $ | ― | ― | % |
| Sempra Mexico | | 350 | 63 | | | 253 | 58 | | | 197 | 41 | |
| Sempra Renewables | | ― | ― | | | 3 | 1 | | | 3 | ― | |
| Sempra Natural Gas | | 617 | 112 | | | 497 | 114 | | | 581 | 121 | |
| Adjustments and eliminations(1) | | (426) | (77) | | | (318) | (73) | | | (300) | (62) | |
| Total cost of natural gas, electric fuel | | | | | | | | | | | | |
| and purchased power | $ | 552 | 100 | % | $ | 435 | 100 | % | $ | 481 | 100 | % |
| | | | | | | | | | | | | | |
| Sempra South American Utilities | $ | 68 | 42 | % | $ | 84 | 47 | % | $ | 66 | 41 | % |
| Sempra Mexico | | 14 | 8 | | | 10 | 6 | | | 21 | 13 | |
| Sempra Natural Gas | | 89 | 55 | | | 91 | 51 | | | 90 | 57 | |
| Adjustments and eliminations(1) | | (8) | (5) | | | (7) | (4) | | | (18) | (11) | |
| Total other cost of sales | $ | 163 | 100 | % | $ | 178 | 100 | % | $ | 159 | 100 | % |
| (1) | Includes eliminations of intercompany activity. |
| (2) | Excludes depreciation and amortization, which are shown separately on the Consolidated Statements of Operations. |
Revenues from our energy-related businesses increased by $29 million (2%) to $1.3 billion in 2014. The increase included
| § | $131 million higher revenues at Sempra Mexico primarily due to higher natural gas and power prices and volumes, and higher transportation revenues from the start of operations of a section of the Sonora natural gas pipeline; and |
| § | $67 million increase at Sempra Natural Gas mainly from the favorable impact of higher natural gas prices and volumes in 2014 from its LNG marketing operations, offset by lower revenues from its natural gas marketing activities; offset by |
| § | $110 million higher intercompany eliminations primarily associated with sales between Sempra Natural Gas and Sempra Mexico; and |
| § | $47 million lower revenues at Sempra Renewables mainly due to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in 2013. |
In 2013 compared to 2012, revenues from our energy-related businesses increased by $42 million (3%) to $1.2 billion in 2013. The increase included
| § | $48 million increase at Sempra Mexico primarily due to higher natural gas and power prices, partially offset by the net impact of changes in affiliate agreements; |
| § | $20 million increase at Sempra South American Utilities primarily due to higher electric construction service and energy distribution revenues at Tecnored; and |
| § | $14 million increase at Sempra Renewables mainly from revenues generated by our solar assets placed in service during 2012; offset by |
| § | $36 million decrease at Sempra Natural Gas primarily due to lower power production at Mesquite Power, a portion of which was due to the sale of one 625-MW block of the natural gas-fired power plant, and expiring capacity release contracts related to Rockies Express, offset by higher physical gas sales at natural gas marketing and storage operations, and the impact of higher natural gas prices on LNG marketing operations. |
The cost of natural gas, electric fuel and purchased power for our energy-related businesses increased by $117 million (27%) to $552 million in 2014 primarily due to:
| § | $120 million increase at Sempra Natural Gas primarily due to higher natural gas costs and volumes; and |
| § | $97 million increase at Sempra Mexico primarily due to higher natural gas costs and volumes; offset by |
| § | $108 million higher intercompany eliminations of costs primarily associated with sales between Sempra Natural Gas and Sempra Mexico. |
The cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $46 million (10%) to $435 million in 2013 compared to 2012 primarily due to:
| § | $84 million decrease at Sempra Natural Gas primarily due to lower natural gas costs as a result of lower power production at Mesquite Power, as discussed above, and a decrease at its LNG operations primarily due to lower natural gas sales and lower costs resulting from commercial arrangements entered into with affiliates; offset by |
| § | $56 million increase at Sempra Mexico primarily due to higher natural gas prices and costs associated with greenhouse gas allowances. |
In 2013 compared to 2012, other cost of sales from our energy-related businesses increased by $19 million (12%) to $178 million primarily due to costs associated with higher service revenues at Tecnored and Tecsur, including those related to electric construction and generation projects.
Operation and Maintenance
In the table below, we provide a breakdown of our operation and maintenance expenses by segment.
| OPERATION AND MAINTENANCE 2012-2014 |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| California Utilities: | | | | | | | | | | | | |
| SDG&E | $ | 1,076 | 37 | % | $ | 1,157 | 39 | % | $ | 1,154 | 39 | % |
| SoCalGas | | 1,321 | 45 | | | 1,324 | 44 | | | 1,304 | 44 | |
| Sempra International: | | | | | | | | | | | | |
| Sempra South American Utilities | | 173 | 6 | | | 170 | 6 | | | 177 | 6 | |
| Sempra Mexico | | 121 | 4 | | | 124 | 4 | | | 94 | 3 | |
| Sempra U.S. Gas & Power: | | | | | | | | | | | | |
| Sempra Renewables | | 50 | 2 | | | 46 | 1 | | | 34 | 1 | |
| Sempra Natural Gas | | 181 | 6 | | | 167 | 6 | | | 168 | 6 | |
| Parent and other(1) | | 13 | ― | | | 7 | ― | | | 25 | 1 | |
| Total operation and maintenance | $ | 2,935 | 100 | % | $ | 2,995 | 100 | % | $ | 2,956 | 100 | % |
| (1) | Includes intercompany eliminations recorded in consolidation. |
Sempra Energy Consolidated
Our operation and maintenance expenses decreased by $60 million (2%) to $2.9 billion in 2014 primarily due to:
| § | $81 million decrease at SDG&E, which we discuss below; and |
| § | $3 million decrease at SoCalGas, which we discuss below; offset by |
| § | $14 million increase at Sempra Natural Gas primarily due to higher operating expenses at its LNG operations. |
While our operation and maintenance expenses remained approximately the same at $3.0 billion in 2013 compared to 2012, it included the following activities:
| § | $30 million higher expenses at Sempra Mexico mainly due to higher administrative expenses from the new IEnova public company structure and scheduled plant maintenance at the Mexicali power plant in 2013; |
| § | $20 million increase at SoCalGas, which we discuss below; and |
| § | $12 million increase at Sempra Renewables primarily due to higher corporate allocations, land lease costs for Copper Mountain Solar 3, and operating expenses of Copper Mountain Solar 2 and Mesquite Solar 1 prior to the projects’ deconsolidation in the third quarter of 2013; offset by |
| § | $18 million decrease at Parent and Other mainly due to higher eliminations of intersegment operating costs. |
SDG&E
SDG&E’s operation and maintenance expenses decreased by $81 million (7%) to $1.1 billion in 2014 primarily due to:
| § | $44 million lower expenses associated with CPUC-authorized refundable programs, including $61 million due to lower operation and maintenance expenses at SONGS, for which all costs incurred are fully recovered in revenue (refundable program expenses); |
| § | $23 million lower operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs); and |
| § | $8 million lower legal costs. |
SDG&E’s operation and maintenance expenses remained approximately the same at $1.2 billion in 2013 compared to 2012 and included the following activities:
| § | $36 million higher non-refundable operating costs, including: |
| □ | $10 million recovery from the DOE in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel, and |
| □ | $4 million increase in liability insurance premiums for wildfire coverage in 2013; |
| § | $7 million higher legal costs; and |
| § | $5 million higher operation and maintenance expenses at Otay Mesa VIE; offset by |
| § | $45 million lower refundable program expenses. |
SoCalGas
Operation and maintenance expenses at SoCalGas decreased in 2014 by $3 million, remaining at $1.3 billion, primarily due to:
| § | $18 million lower expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); offset by |
| § | $9 million higher operation and maintenance costs, including labor, contract services and administrative and support costs (non-refundable operating costs); and |
| § | $7 million insurance recovery in 2013 of previously expensed costs. |
SoCalGas’ operation and maintenance expenses increased by $20 million (2%) to $1.3 billion in 2013 compared to 2012 primarily due to:
| § | $76 million higher refundable program expenses; offset by |
| § | $49 million lower non-refundable operating costs; and |
| § | $7 million insurance recovery in 2013 of previously expensed costs. |
Depreciation and Amortization
Sempra Energy Consolidated
Our depreciation and amortization expense was
The increase of $43 million (4%) in 2014 was primarily due to:
| § | $33 million higher depreciation and amortization at SoCalGas from higher utility plant base; |
| § | $18 million net increase in depreciation and amortization at SDG&E mainly from higher utility plant base, offset by lower depreciation from the retirement of SONGS; and |
| § | lower depreciation and amortization in 2013 of $18 million at SDG&E and $15 million at SoCalGas due to the retroactive application to the period of January 1 to December 2012 of the extension of the useful lives of depreciable assets as adopted in the 2012 GRC; offset by |
| § | $16 million lower depreciation at Sempra Renewables mainly related to the deconsolidation of Mesquite Solar 1 and Copper Mountain Solar 2 in 2013; and |
| § | $20 million lower depreciation expense at Sempra Natural Gas largely due to the classification of the second block of the Mesquite Power plant as an asset held for sale in January 2014. |
The increase of $23 million (2%) in 2013 compared to 2012 included
| § | $36 million higher depreciation and amortization at SoCalGas from higher utility plant base; and |
| § | $22 million net increase in depreciation and amortization at SDG&E mainly from Sunrise Powerlink going into service in June 2012 and higher amortization of legacy meters, offset by lower depreciation from the retirement of SONGS; offset by |
| § | lower depreciation and amortization of $18 million at SDG&E and $15 million at SoCalGas due to the retroactive application to the period of January 1 to December 2012 of the extension of the useful lives of depreciable assets as adopted in the 2012 GRC; and |
| § | $12 million lower depreciation expense at Sempra Natural Gas largely due to the sale of one block of the Mesquite Power plant in February 2013. |
Plant Closure Loss
SDG&E has a 20-percent ownership interest in SONGS, a nuclear generating facility near San Clemente, California. SONGS’ Units 2 and 3 were shut down in early 2012 due to steam generator issues and, in June 2013, Edison, the majority owner and operator of SONGS, made the decision to permanently retire these two units. In the second quarter of 2013, SDG&E recorded a pretax charge of $200 million ($119 million after-tax), which represents the portion of SDG&E’s investment in SONGS and associated costs that management estimated may not be recovered in rates based on prior CPUC precedent. In 2014, SDG&E recorded a $6 million charge ($4 million after-tax, not including a $17 million charge to reduce certain tax regulatory assets that we discuss in “Income Taxes” below) to adjust the total loss from plant closure (in addition to the amount recorded in 2013), based on a settlement agreement (approved by the CPUC in November 2014) to the SONGS OII into the SONGS Outage. We discuss SONGS further in Notes 13 and 15 of the Notes to Consolidated Financial Statements.
Gain on Sale of Equity Interests and Assets
Gain on sale of equity interests and assets in 2013 included the $74 million gain ($44 million after-tax) from the sale of one 625-MW block of the Mesquite Power natural gas-fired power plant.
Also included in this line item are gains on the sale of 50-percent equity interests in 2014 and 2013 as follows:
2014:
| § | $27 million ($16 million after-tax) for Copper Mountain Solar 3 |
| § | $19 million ($14 million after-tax) for the first phase of the Energía Sierra Juárez Wind project |
| § | $14 million ($8 million after-tax) for the Broken Bow 2 Wind project |
2013:
| § | $36 million ($22 million after-tax) for Mesquite Solar 1 |
| § | $4 million ($2 million after-tax) for Copper Mountain Solar 2 |
Equity Earnings (Losses), Before Income Tax
Equity earnings (losses) from our equity method investments were
The increase in equity earnings in 2014 was primarily due to:
| § | $20 million equity earnings in 2014 compared to $12 million equity losses in 2013 from investments at Sempra Renewables, including Mesquite Solar 1, the California solar partnership, Fowler Ridge 2 Wind and Copper Mountain Solar 2; and |
| § | $13 million higher equity earnings from Rockies Express. |
Equity losses in 2012 included a write-down of our investment in Rockies Express of $400 million, offset by a $41 million make-whole income tax provision payment received from our previous joint venture partner, Kinder Morgan.
We provide further details about equity method investments in Note 4 and the impairment of our investment in Rockies Express in Note 10 of the Notes to Consolidated Financial Statements.
Other Income, Net
Sempra Energy Consolidated
Other income, net, was
Other income, net, includes equity-related AFUDC at the California Utilities and regulated entities at Sempra Mexico and Sempra Natural Gas; interest on regulatory balancing accounts; gains and losses from our investments and interest rate swaps; foreign currency gains and losses; electrical infrastructure relocation income in Peru; and other, sundry amounts. The investment activity is on dedicated assets in support of certain executive benefit plans, as we discuss in Note 7 of the Notes to Consolidated Financial Statements.
Other income, net, decreased by $3 million (2%) to $137 million in 2014 and included the following activity:
| § | $15 million losses on interest rate and foreign exchange instruments in 2014 compared to $17 million gains in 2013; |
| § | $12 million higher foreign currency losses, primarily at Sempra Mexico; and |
| § | $12 million lower investment gains on dedicated assets in support of our executive retirement and deferred compensation plans; offset by |
| § | $31 million increase in equity-related AFUDC, including: |
| □ | $24 million increase at Sempra Mexico related to construction of the Sonora natural gas pipeline, and |
| □ | $9 million increase at SoCalGas; and |
| § | $17 million higher income from relocation of electrical infrastructure in Peru. |
In 2013 compared to 2012, other income, net, decreased by $32 million (19%) to $140 million primarily due to:
| § | $21 million decrease in equity-related AFUDC, including: |
| □ | $32 million decrease at SDG&E primarily due to completion of construction on the Sunrise Powerlink project in June 2012, and |
| □ | $8 million decrease at SoCalGas, offset by |
| □ | $19 million increase at Sempra Mexico related to construction of the Sonora natural gas pipeline; and |
| § | $9 million foreign currency gains in 2012. |
We provide further details of the components of other income, net, in Note 1 of the Notes to Consolidated Financial Statements.
Interest Expense
The table below shows the interest expense for Sempra Energy Consolidated, SDG&E and SoCalGas.
| INTEREST EXPENSE 2012-2014 |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 554 | $ | 559 | $ | 493 |
| SDG&E | | 202 | | 197 | | 173 |
| SoCalGas | | 69 | | 69 | | 68 |
Sempra Energy Consolidated
In 2013 compared to 2012, our interest expense increased primarily due to:
| § | $46 million decrease in capitalized interest mainly due to projects placed in service, including: SDG&E’s Sunrise Powerlink, which was placed in service in June 2012; Sempra Renewables’ wind and solar projects, which went online in the fourth quarter of 2012; and additional capacity at Sempra Natural Gas’ Mississippi Hub, LLC (Mississippi Hub) facility, which went online in September 2012; and |
| § | $20 million net increase in interest expense primarily related to long-term debt issuances, including: |
| □ | the IEnova debt offering in February 2013, |
| □ | long-term debt issuances in 2012 and 2013 and remarketing of industrial development bonds in 2012 from floating to fixed rates at SDG&E, |
| □ | long-term debt issuances of $1.6 billion in March and September 2012 and November 2013 at Parent and Other, offset by lower interest expense associated with the maturity of $650 million of notes in February and November 2013, and |
| □ | project financing of selected projects at Sempra Renewables. |
SDG&E
In 2013 compared to 2012, SDG&E’s interest expense increased by $24 million (14%) primarily due to lower AFUDC debt as a result of the Sunrise Powerlink project going into service in June 2012, the issuances of long-term debt in 2012 and 2013 and the remarketing of industrial development bonds from floating to fixed rates in 2012.
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 2012-2014 |
| (Dollars in millions) |
| | Years ended December 31, |
| | | | 2014 | | 2013 | | 2012 |
| | | | Income | | Effective | | | Income | | Effective | | | Income | | Effective | |
| | | | tax | | income | | | tax | | income | | | tax | | income | |
| | | | expense | | tax rate | | | expense | | tax rate | | | expense | | tax rate | |
| Sempra Energy Consolidated | $ | 300 | | 20 | % | $ | 366 | | 26 | % | $ | 59 | | 6 | % |
| SDG&E | | 270 | | 34 | | | 191 | | 31 | | | 190 | | 27 | |
| SoCalGas | | 139 | | 29 | | | 116 | | 24 | | | 79 | | 21 | |
| | |
Sempra Energy Consolidated
Sempra Energy’s income tax expense decreased in 2014 due to a lower effective income tax rate, offset by higher pretax income. The lower effective income tax rate was primarily due to:
| § | $63 million income tax expense recorded in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings. We discuss the stock offerings further in Note 1 of the Notes to Consolidated Financial Statements; |
| § | higher income tax benefit in 2014 from foreign currency translation and inflation adjustments; |
| § | a $25 million tax benefit due to the release in 2014 of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments; and |
| § | higher deferred income tax benefits related to renewable energy projects; offset by |
| § | a $38 million U.S. tax on the repatriation of a portion of current year earnings from certain non-U.S. subsidiaries in Mexico and Peru; and |
| § | a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS pursuant to a settlement agreement to resolve the SONGS OII that we discuss in Note 13 of the Notes to Consolidated Financial Statements. |
Sempra Energy’s income tax expense increased in 2013 compared to 2012 due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to:
| § | $63 million income tax expense recorded in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings; |
| § | a $62 million income tax benefit recorded in 2012 for life insurance contracts, of which $54 million was primarily associated with our decision in the second quarter of 2012 to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts; |
| § | lower deferred income tax benefits related to renewable energy projects; |
| § | lower income tax benefit in 2013 relating to certain repairs expenditures that are capitalized for financial statement purposes, including $22 million income tax benefit recorded in 2012 for 2011 resulting from a favorable change made in the third quarter of 2012, as we discuss below; |
| § | lower favorable impact of exclusions from taxable income of the equity portion of AFUDC; and |
| § | lower deductions for self-developed software expenditures; offset by |
| § | a lower unfavorable impact on our effective tax rate in 2013 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; and |
| § | favorable adjustments to prior years’ income tax items in 2013, primarily at SoCalGas. |
We use the deferral method of accounting for investment tax credits (ITC). For certain wind and solar generating assets being placed into service during 2012, we elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting was applied. Grant accounting for cash grants is very similar to the deferral method of accounting for ITC, the primary difference being the recording of a cash grant receivable instead of an income tax receivable. We discuss our accounting for ITC and cash grants further in Note 6 of the Notes to Consolidated Financial Statements.
The results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, 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, as we discuss in Note 1 of the Notes to Consolidated Financial Statements. For 2014, 2013 and 2012, the impacts on the Sempra Energy Consolidated and SDG&E effective income tax rates shown above were not material.
We report as part of our pretax results the income or loss attributable to noncontrolling interests. However, we do not record income taxes for a portion of this income or loss, as some of our entities with noncontrolling interests are currently treated as partnerships for income tax purposes and thus we are only liable for income taxes on the portion of the earnings that are allocated to us. As our entities with noncontrolling interests grow, and as we may continue to invest in such entities, the impact on our effective income tax rate may become more significant.
In 2015, we anticipate that Sempra Energy Consolidated’s effective income tax rate will be approximately 29 percent compared to 20 percent in 2014. This increase is primarily due to a forecasted increase in pretax book income and because we are not currently anticipating similar significant events as incurred in 2014.
In the years 2016 through 2019, we anticipate that Sempra Energy Consolidated’s effective income tax rate will range from 30 percent to 33 percent primarily due to forecasted increases in pretax book income in jurisdictions with higher tax rates, primarily from anticipated commencement of operations at the Cameron LNG Holdings joint venture.
SDG&E
SDG&E’s income tax expense increased in 2014 due to a higher effective tax rate and higher pretax income. Pretax income in 2013 included a $200 million loss from the early closure of SONGS, offset by the favorable impact of the retroactive application of the 2012 GRC in 2013. 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; offset by |
| § | higher favorable adjustments to prior years’ income tax items in 2014. |
SDG&E’s income tax expense increased in 2013 compared to 2012 due to a higher effective tax rate, offset by lower pretax income. The higher effective tax rate was primarily due to:
| § | $22 million income tax benefit recorded in 2012 for 2011 resulting from a favorable change made in the third quarter of 2012 in the income tax treatment of certain repairs expenditures that are capitalized for book purposes; and |
| § | lower favorable impact of exclusions from taxable income of the equity portion of AFUDC. |
In 2015, we anticipate that SDG&E’s effective income tax rate will be approximately 37 percent compared to 34 percent in 2014. This increase is primarily due to a forecasted increase in pretax book income without a proportional increase in the forecasted flow-through deductions. Flow-through deductions are subject to review by the CPUC and, at the CPUC’s discretion, the flow-through benefits of these items could be changed, which could have a material adverse impact on Sempra Energy’s and SDG&E’s earnings, financial condition and cash flow.
In the years 2016 through 2019, we anticipate that SDG&E’s effective income tax rate will range from 37 percent to 38 percent.
SoCalGas
SoCalGas’ income tax expense increased in 2014 due to a higher effective tax rate, offset by slightly lower pretax income. The higher effective tax rate was primarily due to:
| § | $15 million lower favorable adjustments to prior years’ income tax items in 2014; |
| § | higher unfavorable impact on our effective tax rate in 2014 from the reversal through book depreciation of previously recognized tax benefits for a certain portion of utility fixed assets; and |
| § | lower deductions for self-developed software expenditures. |
SoCalGas’ income tax expense increased in 2013 compared to 2012 due to higher pretax income and a higher effective tax rate. The higher effective tax rate was primarily due to:
| § | lower income tax benefit in 2013 relating to certain repairs expenditures for gas assets that are capitalized for financial statement purposes; and |
| § | lower deductions for self-developed software expenditures; offset by |
| § | higher favorable adjustments to prior years’ income tax items in 2013. |
In 2015, we anticipate that SoCalGas’ effective income tax rate will be approximately 31 percent compared to 29 percent in 2014. This increase is primarily due to a forecasted increase in pretax book income without a proportional increase in the forecasted flow-through deductions. Flow-through deductions are subject to review by the CPUC and, at the CPUC’s discretion, the flow-through benefits of these items could be changed, which could have a material adverse impact on Sempra Energy’s and SoCalGas’ earnings, financial condition and cash flow.
In the years 2016 through 2019, we anticipate that SoCalGas’ effective income tax rate will range from 31 percent to 33 percent, primarily due to forecasted increases in pretax book income without a proportional increase in the forecasted flow-through deductions.
The following items are subject to flow-through treatment at the California Utilities:
| § | repairs expenditures related to a certain portion of utility plant 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 assets |
The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico and Sempra Natural Gas has similar flow-through treatment.
Tax Reform
Peru. On December 31, 2014, the Peruvian government passed a tax reform law, effective on January 1, 2015. Among other changes, the new law imposes a gradual decrease in the corporate income tax rate from 30 percent in 2014 to 26 percent in 2019 and beyond, as well as a gradual increase in the dividend withholding tax rate from 4.1 percent in 2014 to 9.3 percent in 2019 and beyond. To reflect the impact of the decrease to the Peruvian corporate income tax rate, we remeasured our Peruvian deferred tax balances, resulting in an additional $18 million of deferred tax benefit that was recorded in the fourth quarter of 2014. There is no immediate impact of the increase to the Peruvian dividend withholding tax rate, because the withholding tax will be accrued at the shareholder level when Peruvian earnings are actually distributed.
Chile. The 2014 Chilean Tax Reform Bill (Tax Reform Bill) became effective on September 29, 2014. Taxpayers have an option of being taxed under two approaches. For the approach that we intend to select, the corporate income tax rates will increase gradually, between 2014 and 2017, from 21 percent to 27 percent. To reflect the impact of the change in tax law, we remeasured our Chilean deferred tax balances, which resulted in an additional $6 million of deferred tax expense that was recorded in the third quarter of 2014. The Tax Reform Bill also imposes a tax on earnings distributed to non-Chilean shareholders. However, since Sempra Energy intends to indefinitely reinvest the cumulative Chilean earnings, there is no impact from the Tax Reform Bill’s shareholder level income tax.
Mexico. In December 2013, the Mexican Congress passed tax reform legislation with the following impacts on Sempra Energy and our Sempra Mexico segment:
| § | Higher Corporate Tax Rate: The new corporate income tax rate is 30 percent for 2014 and future years. In 2013, we recorded $13 million additional income tax expense related to the revaluation of deferred tax liabilities. |
| § | Tax Consolidation: The consolidation rules under the previous income tax law were replaced with new rules under which tax benefits are recaptured in three years instead of five years. However, as a result of the IEnova corporate reorganization, we were required to make a prepayment of approximately $81 million against future income tax liability in 2014. Of the $81 million, $23 million was utilized in 2014. The remaining prepayment expires between 2016 and 2022. We currently believe that we will fully utilize the $58 million remaining prepayment before it expires. |
| § | 10-Percent Dividends Tax: A new “corporate” tax on dividends is payable by the Mexican entity that distributes the dividend to its foreign shareholder, which increased Mexico’s income tax rate to an effective 37 percent. Under the law, this tax is reduced or offset in accordance with bilateral tax treaties. The dividends from our Mexican entities to Sempra Energy will be to a country which has a bilateral tax treaty with Mexico that we expect will fully offset the tax. Accordingly, we do not expect this rule to have a material financial impact. |
United States. In December 2014, the Tax Increase Prevention Act of 2014 (2014 Tax Act) was signed into law. The 2014 Tax Act included a one-year retroactive extension of certain business income tax provisions that had expired at the end of 2013, including 50 percent bonus depreciation and the research credit. The effects of these changes in the tax law have resulted in a tax benefit for the research credit. The impact of bonus depreciation is discussed below.
In January 2013, the American Taxpayer Relief Act of 2012 (2012 Tax Act) was signed into law. The 2012 Tax Act included retroactive extensions from January 1, 2012 through December 31, 2013 of certain business income tax provisions that had expired at the end of 2011, including the look-through rule. The look-through rule allows, under certain situations, for certain non-operating income (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. The retroactive application of the look-through rule to 2012 resulted in a $6 million income tax benefit. However, as the 2012 Tax Act was not signed into law as of December 31, 2012, the extension of the look-through rule has been treated as a 2013 event, and the related income tax benefit for 2012 was recorded in the first quarter of 2013. The 2012 Tax Act also extended the 50 percent bonus depreciation for qualified property placed in service before January 1, 2014, the impact of which we discuss below.
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act included the extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 and an increase in the rate of bonus depreciation from 50 percent to 100 percent. This increased rate only applies to certain investments made after September 8, 2010 through December 31, 2012. Self-constructed property, where the construction period exceeds one year, construction started between December 31, 2007 and January 1, 2013, and the property is placed in service by December 31, 2013, qualified for bonus depreciation in 2013 at either the original or increased rate.
Due to the extension of bonus depreciation, Sempra Energy generated a U.S. federal net operating loss (NOL) in 2011, 2012, 2013 and 2014. We currently project that the total NOL will not be fully utilized until approximately 2019. Because of the carryforward of NOL and U.S. federal income tax credits discussed below, Sempra Energy made no U.S. federal income tax payments in 2014 and expects no such payments in years 2015 through 2019. Because bonus depreciation only creates a temporary difference between Sempra Energy’s U.S. federal income tax return and its U.S. GAAP financial statements, it does not impact Sempra Energy’s effective income tax rate. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.
SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011 and 2012 primarily due to bonus depreciation. SDG&E and SoCalGas expect these NOL carryforwards, on a stand-alone basis, to be fully utilized in 2015. Because bonus depreciation only creates a temporary difference between SDG&E’s and SoCalGas’ U.S. federal income tax returns and U.S. GAAP financial statements, it does not impact SDG&E’s and SoCalGas’ effective income tax rates. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.
Bonus depreciation, in addition to impacting Sempra Energy’s and SDG&E’s U.S. federal income tax payments, will also have a temporary impact on their ability to utilize their U.S. federal income tax credits, which primarily are investment tax credits and production tax credits generated by current and future renewable energy investments. However, based on current projections, Sempra Energy and SDG&E do not expect, based on more-likely-than-not criteria required under U.S. GAAP, any of these income tax credits to expire prior to the end of their 20-year carryforward period, as allowed under current U.S. federal income tax law. Bonus depreciation increases the deferred income tax liability component of SDG&E’s and SoCalGas’ rate base, which reduces rate base.
We had planned to begin repatriating a portion of earnings beginning in 2013 from certain of our non-U.S. subsidiaries in Mexico and Peru. Due to the income tax expense resulting from a corporate reorganization in connection with the IEnova stock offerings that we discuss in Note 1 of the Notes to Consolidated Financial Statements, we made a distribution in 2013 of approximately $200 million from our non-U.S. subsidiaries. This distribution was from previously taxed income and was not subject to additional U.S. federal income tax. We revised our plan in 2013 to begin repatriating a portion of earnings in 2014.
Currently, all repatriated earnings from January 1, 2014 forward (reduced for previously taxed income) are subject to U.S. income tax (with credits for foreign income taxes), and repatriation from Peru is subject to local country withholding tax. We made distributions of $288 million from our non-U.S. subsidiaries in 2014. Approximately $100 million of this distribution was from previously taxed income and will not be subject to additional U.S. federal income tax. We intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2014. Therefore, we do not intend to use these cumulative undistributed earnings as a source of funding for U.S. operations.
Foreign 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.
The income tax expense of our South American subsidiaries is similarly impacted by the factors we discuss above. Such impact was not material in 2014, 2013 or 2012.
For Sempra Energy Consolidated, the impacts at Sempra Mexico in 2012-2014 related to the factors described above are as follows:
| MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Income tax benefit (expense) on currency exchange | | | | | | |
| | rate movement of monetary assets and liabilities | $ | 22 | $ | (6) | $ | (6) |
| Translation of non-U.S. deferred income tax balances | | 15 | | 1 | | (2) |
| Income tax expense on inflation | | (3) | | ― | | (2) |
| | Total impact included in Income Tax Benefit (Expense) | | 34 | | (5) | | (10) |
| After-tax (losses) gains on Mexican peso exchange rate | | | | | | |
| | instruments (included in Other Income, Net) | | (17) | | 4 | | 6 |
| Net impact on Sempra Energy Consolidated | | | | | | |
| | Statements of Operations | $ | 17 | $ | (1) | $ | (4) |
Equity Earnings, Net of Income Tax
Sempra Energy Consolidated
Equity earnings of unconsolidated subsidiaries, net of income tax, which are all from Sempra South American Utilities’ and Sempra Mexico’s equity method investments, were
The increase in 2014 was primarily due to $11 million equity losses in 2013 related to our investments in two Argentine natural gas utility holding companies, as we discuss in Note 4 of the Notes to Consolidated Financial Statements.
The decrease in 2013 compared to 2012 was primarily due to:
| § | $11 million equity losses related to our investments in two Argentine natural gas utility holding companies, including $7 million noncash impairment charge in the first quarter of 2013 and $4 million loss from the sale of the investments in the second quarter of 2013, as we discuss in Note 4 of the Notes to Consolidated Financial Statements; and |
| § | $4 million of equity losses in 2013 from our Eletrans S.A. and Eletrans II S.A. (collectively, Eletrans) joint ventures in Chile resulting from a forward exchange contract to manage foreign currency exchange rate risk; offset by |
| § | $3 million higher earnings in 2013 from Sempra Mexico’s joint-venture interest in pipeline assets. |
Earnings Attributable to Noncontrolling Interests
Sempra Energy Consolidated
Earnings attributable to noncontrolling interests were $100 million for 2014 compared to $79 million for the same period in 2013. The net change of $21 million included
| § | $21 million increase in earnings attributable to noncontrolling interests of IEnova in 2014; and |
| § | $5 million increase in earnings attributable to noncontrolling interests at Sempra South American Utilities; offset by |
| § | $4 million decrease in earnings attributable to noncontrolling interest at Otay Mesa VIE in 2014. |
Earnings attributable to noncontrolling interests were $79 million for 2013 compared to $55 million for the same period in 2012. The net change of $24 million included
| § | $26 million earnings attributable to noncontrolling interests of IEnova in 2013; offset by |
| § | $2 million lower earnings attributable to noncontrolling interest at Otay Mesa VIE in 2013. |
SDG&E
Earnings attributable to noncontrolling interest at Otay Mesa VIE decreased by $4 million (17%) to $20 million in 2014.
In 2013 compared to 2012, earnings attributable to noncontrolling interest at Otay Mesa VIE decreased by $2 million (8%) to $24 million.
Earnings
We summarize variations in overall earnings in “Overall Results of Operations of Sempra Energy and Factors Affecting the Results” above. We discuss variations in earnings (losses) by segment above in “Segment Results.”
TRANSACTIONS WITH AFFILIATES
We provide information about our related party transactions in Note 1 of the Notes to Consolidated Financial Statements.
BOOK VALUE PER SHARE
Sempra Energy’s book value per share on the last day of each year was
The increases in 2014 and 2013 were primarily the result of comprehensive income exceeding dividends. In 2013, the increase was also attributable to the IEnova public offerings.
CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW
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.
Sempra Energy Consolidated cash and cash equivalents decreased $334 million in 2014 to $570 million. Cash flows from operations were $2.2 billion. Significant investing and financing activity affecting capital resources, liquidity and cash flows in 2014 was
| § | $148 million cash proceeds from Sempra Renewables’ sale of 50-percent equity interests in Copper Mountain Solar 3 ($66 million) and Broken Bow 2 Wind ($58 million) and Sempra Mexico’s sale of a 50-percent equity interest in the first phase of the Energía Sierra Juárez wind generation project ($24 million) |
| § | $(121) million cash paid to acquire a 50-percent equity interest in four California solar projects |
| § | long-term debt issuances of $3.3 billion, including $500 million at Sempra Energy, $100 million at SDG&E, $750 million at SoCalGas, and $1.8 billion issuances of credit facility borrowings with maturities greater than 90 days at Sempra Energy, Sempra South American Utilities and Sempra Mexico |
| § | $(2) billion of long-term debt retirements and paydowns, including debt retirements of $800 million at Sempra Energy and $250 million at SoCalGas, and $948 million paydown of credit facility borrowings with maturities greater than 90 days at Sempra Energy and Sempra South American Utilities |
| § | $(3.1) billion in expenditures for property, plant and equipment, including $1.1 billion at each of SDG&E and SoCalGas |
| § | $(598) million common dividends paid |
| § | $(167) million in net advances to unconsolidated affiliates |
We discuss these events in more detail later in this section.
Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 5 of the Notes to Consolidated Financial Statements, 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 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 year-end 2014 on these three credit facilities:
| AVAILABLE FUNDS AT DECEMBER 31, 2014 |
| (Dollars in millions) |
| | | Sempra Energy | | |
| | | Consolidated | SDG&E | SoCalGas |
| Unrestricted cash and cash equivalents(1) | $ | 570 | $ | 8 | $ | 85 |
| Available unused credit(2) | | 2,469 | | 312 | | 481 |
| (1) | Amounts at Sempra Energy Consolidated include $469 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below. |
| (2) | Available credit is the total available on Sempra Energy's, Sempra Global's and the California Utilities' credit facilities that we discuss in Note 5 of the Notes to Consolidated Financial Statements. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $658 million for each utility and a combined total of $877 million. SDG&E's and SoCalGas' available funds reflect commercial paper outstanding of $346 million and $50 million, respectively, supported by the line. SoCalGas' availability reflects the impact of SDG&E's use as of December 31, 2014 of the combined credit available on the line. Some of Sempra Energy's subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $865 million at December 31, 2014. Available unused credit on these lines totaled $536 million at December 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 |
Sempra Energy and the California Utilities have ready access to the long-term debt markets and are not currently constrained in their ability to borrow at reasonable rates. However, changing economic conditions could affect the availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of completion of large projects at Sempra International and Sempra U.S. Gas & Power. 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.
At December 31, 2014 and 2013, our cash and cash equivalents held in non-U.S. jurisdictions that were unavailable to fund U.S. operations unless repatriated were $469 million and $814 million, respectively. As we discuss in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above, we made distributions of approximately $288 million and $200 million in 2014 and 2013, respectively, from our non-U.S. subsidiaries. Approximately $100 million of the 2014 distribution, and all of the 2013 distribution, was from previously taxed income and will not be subject to additional U.S. federal income tax. We intend to continue to indefinitely reinvest our cumulative undistributed non-U.S. earnings through December 31, 2014. 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. However, changes in asset values may, along with a number of other factors such as changes to discount rates, assumed rates of returns, mortality tables, and regulations, impact funding requirements for pension and other postretirement benefit plans and SDG&E’s nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.
On February 20, 2015, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.70 per share ($2.80 annually), an increase of $0.04 per share ($0.16 annually) from $0.66 per share ($2.64 annually) authorized in February 2014. Declarations of dividends on our common stock are made at the discretion of the board. While we view dividends as an integral component of shareholder return, the amount of future dividends will depend upon earnings, cash flows, financial and legal requirements, and other relevant factors at that time.
On February 21, 2014, our board of directors approved an increase to Sempra Energy’s quarterly common stock dividend to $0.66 per share ($2.64 annually), an increase of $0.03 per share ($0.12 annually) from $0.63 per share ($2.52 annually) authorized in February 2013. We provide further information regarding dividends and dividend restrictions in “Dividends” below and under “Restricted Net Assets” in Note 1 of the Notes to Consolidated Financial Statements.
Short-Term Borrowings
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 sources of short-term debt funding in 2014. At our California Utilities, short-term debt is used to meet working capital needs and temporarily finance capital expenditures.
The following table shows selected statistics for our commercial paper borrowings for 2014:
| COMMERCIAL PAPER STATISTICS | | | | | | | | |
| (Dollars in millions) | | | | | | | | |
| | Sempra Energy Consolidated | | SDG&E | | SoCalGas |
| Amount outstanding at December 31, 2014 | $ | 1,564 | | $ | 246 | | $ | 50 |
| Weighted average interest rate at December 31, 2014 | | 0.59% | | | 0.27% | | | 0.25% |
| | | | | | | | | | |
| Maximum month-end amount outstanding during 2014(1) | $ | 1,935 | | $ | 246 | | $ | 129 |
| | | | | | | | | | |
| Monthly weighted average amount outstanding during 2014 | $ | 1,264 | | $ | 56 | | $ | 24 |
| Monthly weighted average interest rate during 2014 | | 0.59% | | | 0.16% | | | 0.17% |
| (1) | The largest amount outstanding at the end of the last day of any month during the year. |
Significant cash flows impacting commercial paper levels at Sempra Energy during 2014 included
| § | debt retirements ($800 million); |
| § | common stock dividend payments ($598 million) by Sempra Energy; |
| § | acquisition of a 50-percent equity interest in four California solar projects ($121 million); and |
| § | interest payments on debt (approximately $200 million); offset by |
| § | long-term debt issuance at Sempra Energy ($500 million); |
| § | repatriated funds received from non-U.S. subsidiaries ($288 million); |
| § | common stock dividends received from SDG&E ($200 million) and SoCalGas ($100 million); |
| § | cash proceeds from the sale of 50-percent equity interests in Broken Bow 2 Wind ($58 million) and Copper Mountain Solar 3 ($66 million); and |
| § | cash proceeds from a construction loan related to Copper Mountain Solar 3 ($84 million, net of financing costs). |
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 common stock dividends of $100 million in 2014, $50 million in 2013 and $250 million in 2012. As a result of the increase in SoCalGas’ capital investment programs over the next few years, and an increase in SoCalGas’ authorized common equity weighting effective January 1, 2013 as approved by the CPUC in the most recent cost of capital proceeding, SoCalGas’ dividends on common stock declared on an annual historical basis may not be indicative of future declarations, or may be temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments.
SDG&E declared and paid common stock dividends of $200 million in 2014. As a result of SDG&E’s large capital investment program over the past few years, SDG&E did not pay common dividends to Sempra Energy in 2013 or 2012. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E has resumed the declaration and payment of common stock dividends in 2014.
In October 2013, SDG&E redeemed all of its outstanding preferred stock for $83 million (including call premium and accrued dividends), which we discuss further in Note 11 of the Notes to Consolidated Financial Statements.
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-related filings, as of December 31, 2014, SDG&E’s ERRA balance is undercollected by $280 million. 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 May 2014, the CPUC issued a final decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $242 million, which rate increase was effective on August 1, 2014. With these rate changes, and assuming that actual energy resource costs incurred approximate what was assumed in the approved 2014 ERRA revenue requirement, management expects the undercollected balance in ERRA to decrease between now and the end of 2015. We discuss the ERRA Trigger and the status of the ERRA filings further in Note 14 of the Notes to Consolidated Financial Statements 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. In 2014, we purchased additional shares in Luz del Sur for $74 million, increasing our ownership from 79.8 percent to 83.6 percent. Also, as of December 31, 2014, Chilquinta Energía has loaned $40 million to an affiliate to finance development projects. We discuss these transactions in Note 1 of the Notes to Consolidated Financial Statements.
Sempra Mexico
We expect projects in Mexico to be funded through a combination of available funds, funds internally generated by the Mexico businesses, securities issuances, project financing and partnering in joint ventures. In June and August 2014, IEnova entered into two three-year term, corporate revolving credit facility agreements providing $200 million and $100 million, respectively, to finance working capital and for general corporate purposes. In 2014, IEnova drew down $145 million from the first facility and $51 million from the second facility. In June 2014, IEnova also entered into a $240 million loan to finance the construction of the first phase of Energía Sierra Juárez, as we discuss in Note 5 of the Notes to Consolidated Financial Statements. The loan agreement provides for a $31.7 million letter of credit facility. IEnova also entered into a separate, Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project. In June 2014, Sempra Mexico drew down $82 million from the loan.
In July 2014, Sempra Mexico sold a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold. Sempra Mexico’s interest in Energía Sierra Juárez is now accounted for under the equity method, and the $82 million of long-term debt was deconsolidated at the time of sale, as we discuss in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
In 2014, Sempra Mexico loaned $123 million to affiliates of its joint venture with PEMEX to finance projects, as we discuss in Note 1 of the Notes to Consolidated Financial Statements.
Sempra Renewables
We expect Sempra Renewables to require funds for the development of and investment in electric renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales. The Sempra Renewables projects have planned in-service dates through 2016. In March 2014, Sempra Renewables entered into a $356 million construction loan facility related to Copper Mountain Solar 3. Copper Mountain Solar 3 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 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. In May 2014, Sempra Renewables invested $121 million (as adjusted for financial position at closing) to become a 50-percent partner with ConEdison Development in four solar projects in California (the California solar partnership). In October 2014, Sempra Renewables received $72 million in proceeds from a private notes offering related to Broken Bow 2 Wind. In November 2014, Sempra Renewables sold a 50-percent equity interest in Broken Bow 2 Wind to ConEdison Development. Sempra Renewables’ interest in Broken Bow 2 Wind is now accounted for under the equity method, and its long-term debt was deconsolidated upon the sale. Sempra Renewables received $58 million in cash from the sale. We discuss these financings and transactions in Notes 3 and 5 of the Notes to Consolidated Financial Statements.
Sempra Natural Gas
We expect Sempra Natural Gas to require funding for the development and expansion of its portfolio of projects, which may be financed through a combination of operating cash flow, funding from the parent and project financing. Sempra Natural Gas expects to invest approximately $110 million in Rockies Express to repay project debt maturing in early 2015.
In January 2014, management approved a plan to sell the remaining 625-MW block of the Mesquite Power plant. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining block of the plant. We anticipate the sale will close in the first half of 2015, subject to obtaining third-party consents for the assignment of an associated 25-year power sales contract to the buyer. We discuss the sale further in Note 3 of the Notes to Consolidated Financial Statements.
Sempra Natural Gas, through the Cameron LNG Holdings joint venture, is developing a natural gas liquefaction export facility at the Cameron LNG terminal. The majority of the liquefaction project is project-financed for 16 years under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI), with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. On October 1, 2014, the effective date of the formation of the joint venture, we contributed our share of equity to the joint venture through the contribution of Cameron LNG at its historical value. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. As of October 1, 2014, Sempra Natural Gas began accounting for its investment in the joint venture under the equity method.
On August 6, 2014, Sempra Energy and its project partners executed the project financing documents. Under the financing agreements, Sempra Energy signed completion guarantees for 50.2 percent of the debt, which corresponds to $3.7 billion of the total $7.4 billion principal amount of the debt committed under the financing agreements. The project financing and completion guarantees became effective on October 1, 2014, the effective date of the joint venture formation. The completion guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. The completion guarantees are anticipated to be terminated in the second half of 2019.
We discuss the Cameron LNG Holdings joint venture and joint venture financing further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash or other acceptable collateral 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 receivables or payables with our counterparties at December 31, 2014.
CASH FLOWS FROM OPERATING ACTIVITIES
| CASH PROVIDED BY OPERATING ACTIVITIES |
| (Dollars in millions) |
| | 2014 | 2014 change | 2013 | 2013 change | 2012 |
| Sempra Energy Consolidated | $ | 2,161 | $ | 377 | 21 | % | $ | 1,784 | $ | (234) | (12) | % | $ | 2,018 |
| SDG&E | | 1,097 | | 378 | 53 | | | 719 | | (382) | (35) | | | 1,101 |
| SoCalGas | | 765 | | 84 | 12 | | | 681 | | (165) | (20) | | | 846 |
Sempra Energy Consolidated
Cash provided by operating activities at Sempra Energy increased in 2014 primarily due to:
| § | $277 million increase in net undercollected regulatory balancing accounts in 2014 at the California Utilities (including long-term amounts included in regulatory assets) compared to a $411 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; |
| § | $44 million decrease in accounts receivable in 2014 compared to a $273 million increase in 2013; the change was mainly due to a $30 million decrease at SoCalGas in 2014 compared to a $113 million increase in 2013, primarily due to a decrease in physical gas sales in December 2014 compared to December 2013, and a $39 million decrease in natural gas sales at Sempra Natural Gas in 2014 compared to a $69 million increase in 2013; |
| § | $109 million increase in accounts payable in 2014 compared to a $28 million decrease in 2013, mainly due to an increase in 2014 related to natural gas purchased at SoCalGas; and |
| § | $82 million decrease in settlement payments and associated legal fees for wildfire claims at SDG&E in 2014 compared to 2013; offset by |
| § | $133 million increase in inventory in 2014 compared to a $116 million decrease in 2013; the 2014 increase was mainly due to a $113 million increase at SoCalGas, primarily due to higher natural gas storage volume; and |
| § | $86 million lower net income, adjusted for noncash items included in earnings, in 2014. |
Cash provided by operating activities at Sempra Energy decreased in 2013 compared to 2012 due to:
| § | $110 million decrease in net overcollected regulatory balancing accounts in 2013 at SoCalGas (including long-term amounts included in regulatory assets) compared to a $31 million increase in net overcollected regulatory balancing accounts in 2012; |
| § | $273 million increase in accounts receivable in 2013, primarily due to a $60 million increase at SoCalGas as a result of an increase in billing rates in 2013, and a $69 million increase in natural gas sales at Sempra Natural Gas in 2013; |
| § | $375 million of funds received from wildfire litigation settlements at SDG&E in 2012; and |
| § | $85 million payment received by SDG&E in 2012 for third party transmission line access (which we discuss in Note 15 of the Notes to Consolidated Financial Statements); offset by |
| § | $259 million higher net income, adjusted for noncash items included in earnings, in 2013; |
| § | a $203 million decrease in settlement payments and associated legal fees in 2013 for wildfire claims at SDG&E; and |
| § | $116 million decrease in inventory in 2013 (including an $82 million decrease at SoCalGas) compared to a $78 million increase in 2012. |
SDG&E
Cash provided by operating activities at SDG&E increased in 2014 primarily due to:
| § | $47 million increase in net undercollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to a $301 million increase in 2013, as follows: |
| □ | the increase in 2014 in the net undercollected regulatory balancing accounts was primarily due to: |
| § | $89 million increase for electric transmission, |
| § | $88 million increase for amounts associated with electric rate design, |
| § | $76 million increase for natural gas transportation, and |
| § | $24 million increase for electric distribution, offset by |
| § | $162 million decrease associated with the delayed decision in the 2012 GRC, |
| § | $42 million decrease for electric commodity, and |
| § | $29 million increase in overcollected balancing accounts associated with public purpose programs. |
| □ | the increase in 2013 in the net undercollected regulatory balancing accounts was primarily due to: |
| § | $105 million increase for electric commodity, |
| § | $103 million increase associated with the delayed decision in the 2012 GRC, |
| § | $60 million increase for electric distribution, and |
| § | $27 million increase associated with electric rate design, offset by |
| § | $29 million decrease in the undercollected balance for electric transmission; and |
| § | $82 million decrease in settlement payments and associated legal fees for wildfire claims in 2014 compared to 2013. |
Cash provided by operating activities at SDG&E decreased in 2013 compared to 2012 primarily due to:
| § | $375 million of funds received from wildfire litigation settlements in 2012; |
| § | $85 million payment received in 2012 for third party transmission line access; and |
| § | $50 million increase in income taxes receivable in 2013 compared to an $85 million decrease in 2012; offset by |
| § | $301 million increase in net undercollected regulatory balancing accounts in 2013 (including long-term amounts included in regulatory assets) compared to a $322 million increase in 2012, as follows: |
| □ | the increase in the net undercollected balancing accounts in 2013 was primarily due to: |
| § | $103 million increase in the net undercollected balance due to the adoption of the 2012 GRC in 2013, and |
| § | $204 million increase in the undercollected balancing account for electric resource cost. |
| □ | the increase in net undercollected regulatory balancing accounts in 2012 was primarily due to: |
| § | $214 million undercollection of electric resource costs, and |
| § | $71 million return of prior year’s overcollection to customers and $83 million of unrecovered current year spending for advanced metering infrastructure costs, offset by |
| § | $54 million reduction of prior year’s undercollected electric distribution fixed costs; |
| § | $40 million higher net income, adjusted for noncash items included in earnings, in 2013; and |
| § | $203 million decrease in settlement payments and associated legal fees in 2013 for wildfire claims. |
SoCalGas
Cash provided by operating activities at SoCalGas increased in 2014 primarily due to:
| § | $156 million increase in accounts payable in 2014 compared to a $54 million decrease in 2013, primarily due to a $75 million increase in natural gas purchases in 2014 compared to a $65 million decrease in 2013; |
| § | $30 million decrease in accounts receivable in 2014 compared to a $113 million increase in 2013, primarily due to a decrease in physical gas sales in December 2014 compared to December 2013; and |
| § | $27 million higher net income, adjusted for noncash items included in earnings, in 2014 compared to 2013; offset by |
| § | $230 million decrease in net overcollected regulatory balancing accounts in 2014 (including long-term amounts included in regulatory assets) compared to $110 million decrease in 2013: |
| □ | the decrease in 2014 in the net overcollected regulatory balancing accounts was primarily due to: |
| § | $216 million increase in the undercollected position associated with the fixed cost balancing accounts, and |
| § | $35 million decrease in the overcollected balancing accounts associated with the public purpose programs, offset by |
| § | $52 million decrease in the undercollected balance associated with the delayed decision in the 2012 GRC. |
| □ | the decrease in 2013 in the net overcollected balancing accounts was primarily due to: |
| § | $26 million increase in the net undercollected balancing accounts associated with the adoption of the 2012 GRC in 2013, and |
| § | $86 million change in the balancing account for fixed costs associated with core customer activities. In 2013, this account changed from a $36 million overcollected balance to a $50 million undercollected balance at year-end; and |
| § | $113 million increase in inventory in 2014 compared to an $82 million decrease in 2013, primarily due to higher volume of natural gas added to storage in 2014 compared to 2013 as a result of colder than normal weather in the fourth quarter of 2013, which left a lower volume of natural gas in storage at the end of 2013 compared to the end of 2012, combined with higher gas prices in 2014. |
Cash provided by operating activities at SoCalGas decreased in 2013 compared to 2012 primarily due to:
| § | $110 million decrease in overcollected regulatory balancing accounts in 2013 (including long-term amounts included in regulatory assets) compared to a $31 million increase in 2012. The decrease in the net overcollected balancing accounts in 2013 was primarily due to: |
| □ | $26 million increase in the net undercollected balancing accounts due to the adoption of the 2012 GRC in 2013, and |
| □ | $86 million change in the balancing account for fixed costs associated with core customer activities. In 2013, this account changed from a $36 million overcollected balance to a $50 million undercollected balance at year-end; |
| § | $113 million increase in accounts receivable in 2013, primarily due to a $60 million increase in trade accounts receivable and a $30 million increase in physical gas sales. The $60 million increase in trade accounts receivable is primarily due to the increase in billing rates in 2013 compared to 2012; and |
| § | $54 million decrease in accounts payable in 2013 compared to a $54 million increase in 2012; offset by |
| § | $92 million higher net income, adjusted for noncash items included in earnings, in 2013; and |
| § | $82 million decrease in inventory in 2013 compared to $1 million increase in 2012, due to higher net withdrawal volume and higher rate of natural gas withdrawn in 2013. |
The table below shows the contributions to pension and other postretirement benefit plans for each of the past three years.
| CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS 2012-2014 |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 128 | $ | 133 | $ | 123 | | $ | 16 | $ | 27 | $ | 39 |
| SDG&E | | 56 | | 51 | | 45 | | | 14 | | 14 | | 13 |
| SoCalGas | | 39 | | 59 | | 47 | | | ― | | 9 | | 23 |
The passage of the Highway and Transportation Funding Act of 2014 decreased the minimum contributions required for single employer defined benefit plans for 2014 and future years, impacting each of the domestic pension plans.
CASH FLOWS FROM INVESTING ACTIVITIES
| CASH USED IN INVESTING ACTIVITIES |
| (Dollars in millions) |
| | 2014 | 2014 change | 2013 | 2013 change | 2012 |
| Sempra Energy Consolidated | $ | (3,342) | $ | 1,653 | 98 | % | $ | (1,689) | $ | (1,469) | (47) | % | $ | (3,158) |
| SDG&E | | (1,126) | | 153 | 16 | | | (973) | | (262) | (21) | | | (1,235) |
| SoCalGas | | (1,104) | | 376 | 52 | | | (728) | | 85 | 13 | | | (643) |
Sempra Energy Consolidated
Cash used in investing activities at Sempra Energy increased in 2014 primarily due to:
| § | $551 million increase in capital expenditures; |
| § | $371 million of proceeds received in 2013 from Sempra Natural Gas’ sale of a block of its Mesquite Power plant; |
| § | $214 million invested in Sempra Renewables’ joint venture partnerships in 2014; |
| § | $238 million U.S. Treasury grant proceeds received in 2013; |
| § | $153 million increase in net advances to affiliates in 2014; and |
| § | $50 million distribution in 2013 from RBS Sempra Commodities LLP (RBS Sempra Commodities). |
Cash used in investing activities at Sempra Energy decreased in 2013 compared to 2012 primarily due to:
| § | $384 million decrease in capital expenditures; |
| § | $371 million proceeds received from Sempra Natural Gas’ 2013 sale of a block of its Mesquite Power plant; |
| § | $373 million invested in wind assets in 2012, including $291 million in the Flat Ridge 2 Wind; |
| § | $238 million U.S. Treasury grant proceeds; |
| § | $103 million proceeds received from the sale of a 50-percent equity interest in Mesquite Solar 1; and |
| § | $72 million proceeds received from the sale of a 50-percent equity interest in Copper Mountain Solar 2; offset by |
| § | $55 million lower distributions from investments, including a $50 million distribution in 2013 from RBS Sempra Commodities. |
SDG&E
Cash used in investing activities at SDG&E increased in 2014 primarily due to a $122 million increase in capital expenditures.
In 2013 compared to 2012, cash used in investing activities at SDG&E decreased primarily due to a $259 million decrease in capital expenditures, primarily due to the completion of the Sunrise Powerlink project in June 2012.
SoCalGas
Cash used in investing activities at SoCalGas increased in 2014 due to:
| § | $342 million increase in capital expenditures; and |
| § | $34 million decrease in advances to Sempra Energy in 2013. |
Cash used in investing activities at SoCalGas increased in 2013 compared to 2012 due to:
| § | $123 million increase in capital expenditures; offset by |
| § | $34 million decrease in advances to Sempra Energy in 2013 compared to a $4 million increase in advances to Sempra Energy in 2012. |
CAPITAL EXPENDITURES AND INVESTMENTS
The table below shows our expenditures for property, plant and equipment, and for investments. We provide capital expenditure information by segment in Note 16 of the Notes to Consolidated Financial Statements.
| SEMPRA ENERGY CONSOLIDATED |
| CAPITAL EXPENDITURES AND INVESTMENTS/ACQUISITIONS |
| (Dollars in millions) |
| | Property, plant and equipment | | Investments and acquisition of businesses |
| 2014 | $ | 3,123 | | $ | 240 |
| 2013 | | 2,572 | | | 22 |
| 2012 | | 2,956 | | | 445 |
| 2011 | | 2,844 | | | 941 |
| 2010 | | 2,062 | | | 611 |
California Utilities
The California Utilities’ capital expenditures for property, plant and equipment were
| (Dollars in millions) | | 2014 | | 2013 | | 2012 |
| SDG&E | $ | 1,100 | $ | 978 | $ | 1,237 |
| SoCalGas | | 1,104 | | 762 | | 639 |
Capital expenditures at the California Utilities in 2014 consisted primarily of:
SDG&E
| § | $554 million of improvements to natural gas and electric distribution systems |
| § | $458 million of improvements to electric transmission systems |
| § | $37 million for substation expansions (transmission) |
| § | $51 million for electric generation plants and equipment |
SoCalGas
| § | $859 million of improvements to distribution and transmission systems and storage facilities, and for pipeline safety |
| § | $230 million for advanced metering infrastructure |
| § | $15 million for other natural gas projects |
Sempra South American Utilities
Sempra South American Utilities had capital expenditures at its utilities of $174 million in 2014, $200 million in 2013 and $183 million in 2012, related to distribution infrastructure and generation projects, including Santa Teresa, a 100-MW hydroelectric power plant in Peru.
Sempra Mexico
Total capital expenditures in 2014 and 2013 were $325 million and $371 million, respectively, primarily for the development of wind and natural gas pipeline projects. Total capital expenditures in 2012 were $45 million.
Sempra Renewables
Capital expenditures at Sempra Renewables included construction costs for wind and solar projects as follows:
In 2014:
| § | $114 million for construction of Broken Bow 2 Wind |
| § | $74 million for construction of Copper Mountain Solar 3 |
In 2013:
| § | $93 million for Copper Mountain Solar 3 |
| § | $46 million for Mesquite Solar 1 |
| § | $26 million for Broken Bow 2 Wind |
| § | $9 million for Copper Mountain Solar 2 |
In 2012:
| § | $399 million for Mesquite Solar 1 |
| § | $315 million for Copper Mountain Solar 2 |
Sempra Natural Gas
In 2014, 2013 and 2012, Sempra Natural Gas had $135 million, $36 million and $48 million, respectively, of capital expenditures and development costs related to the Cameron LNG terminal and liquefaction project.
Capital expenditures at Sempra Natural Gas storage facilities were
| § | $58 million in 2014 primarily for additional capacity at Bay Gas Storage Company, Ltd. (Bay Gas) and at Mississippi Hub |
| § | $29 million in 2013 primarily for development of approximately 13 Bcf of additional capacity at Bay Gas and Mississippi Hub |
| § | $61 million in 2012 primarily to increase operational working natural gas storage capacity by approximately 7 Bcf at Mississippi Hub and for the development of approximately 13 Bcf of additional capacity at Bay Gas and Mississippi Hub. |
Sempra Energy Consolidated Investments and Acquisitions
During the years ended December 31, 2014, 2013 and 2012, Sempra Energy made investments in various joint ventures and other businesses, summarized in the following table.
| EXPENDITURES FOR INVESTMENTS AND ACQUISITION OF BUSINESSES(1) |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Sempra Renewables: | | | | | | |
| Auwahi Wind | $ | ― | $ | 1 | $ | 62 |
| Broken Bow 2 Wind | | ― | | 11 | | ― |
| California solar partnership | | 121 | | ― | | ― |
| Copper Mountain Solar 2 | | 3 | | ― | | ― |
| Copper Mountain Solar 3 | | 86 | | ― | | ― |
| Flat Ridge 2 Wind | | ― | | 4 | | 291 |
| Mehoopany Wind | | 4 | | 1 | | 20 |
| Sempra Natural Gas: | | | | | | |
| Cameron LNG Holdings | | 18 | | ― | | ― |
| Mississippi Hub LLC(2) | | ― | | 3 | | 53 |
| Willmut Gas Company | | ― | | 2 | | 19 |
| Parent and other | | 8 | | ― | | ― |
| Total | $ | 240 | $ | 22 | $ | 445 |
| (1) Net of cash acquired. | | | | | | |
| (2) Investment in industrial development bonds. | | | | | | |
Sempra Energy Consolidated Distributions From Investments
Sempra Energy’s Distributions From Investments in 2014, 2013 and 2012 are primarily the return of investment from equity method and other investments at Sempra Renewables and Sempra Natural Gas. Distributions of earnings from equity method investments, which are not included in the table below, are included in cash flows from operations.
During the years ended December 31, 2014, 2013 and 2012, Sempra Energy received distributions from investments in various joint ventures and other investments as summarized by segment in the following table.
| DISTRIBUTIONS FROM INVESTMENTS |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Sempra Renewables(1)(2) | $ | 11 | $ | 67 | $ | 167 |
| Sempra Natural Gas | | ― | | 31 | | 37 |
| Parent and other(3) | | 2 | | 54 | | 3 |
| Total | $ | 13 | $ | 152 | $ | 207 |
| (1) | Distributions in 2013 include $15 million related to U.S. Treasury grant proceeds received at the Auwahi Wind joint venture. |
| (2) | Distributions in 2012 include $165 million related to return of capital as a result of joint ventures entering into loans to finance projects. |
| (3) | Distributions in 2013 include $50 million from RBS Sempra Commodities LLP. |
Purchase and Sale of Bonds Issued by Unconsolidated Affiliate
In November 2009, Sempra Energy, at Parent and Other, purchased $50 million of 2.75-percent bonds issued by Chilquinta Energía S.A., a then unconsolidated affiliate, that were adjusted for Chilean inflation. In October 2012, these bonds were sold for $59 million.
FUTURE 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 2015, we expect to make capital expenditures and investments of approximately $3.3 billion. These expenditures include
| § | $2.4 billion at the California Utilities for capital projects and plant improvements ($1.1 billion at SDG&E and $1.3 billion at SoCalGas) |
| § | $0.9 billion at our other subsidiaries for capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects |
The California Utilities’ 2015 planned capital expenditures and investments include
SDG&E
| § | $700 million for improvements to natural gas and electric distribution systems |
| § | $400 million for improvements to electric transmission systems |
| § | $10 million for electric generation plants and equipment |
SoCalGas
| § | $1.1 billion for improvements to distribution, transmission and storage systems, and for pipeline safety |
| § | $190 million for advanced metering infrastructure |
| § | $30 million for other natural gas projects |
The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.
Over the next five years, 2015 through 2019, and subject to a number of factors including those described below which could cause these estimates to vary substantially, the California Utilities expect to make capital expenditures and investments of:
| § | $6.0 billion at SoCalGas |
In 2015, the expected capital expenditures and investments of approximately $0.9 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 $220 million for capital projects in South America (approximately $170 million in Peru and approximately $50 million in Chile) |
Sempra Mexico
| § | approximately $300 million for capital projects in Mexico, net of project financing, including approximately $180 million and $80 million for the development of the Sonora pipeline and Ojinaga pipeline projects, respectively, both developed solely by Sempra Mexico |
Sempra Renewables
| § | approximately $30 million for the development of renewable projects |
Sempra Natural Gas
| § | approximately $290 million for development of LNG and natural gas transportation projects, including approximately $110 million equity investment in Rockies Express to pay down project debt |
Parent & Other
| § | approximately $40 million related to the build-to-suit lease for Sempra Energy’s future headquarters |
Over the next five years, 2015 through 2019, and subject to the factors described below which could cause these estimates to vary substantially, Sempra Energy expects to make aggregate capital expenditures at its other subsidiaries of approximately $2.8 billion.
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 and Sempra Natural Gas, the amounts also exclude AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial Statements.
Periodically, we review our construction, investment and financing programs and revise them in response to changes in regulation, economic conditions, competition, customer growth, inflation, customer rates, the cost and availability of capital, and environmental requirements. We discuss these considerations in more detail in Notes 13, 14 and 15 of the Notes to Consolidated Financial Statements and in “Factors Influencing Future Performance” below.
Our level of capital expenditures and investments in the next few years may vary substantially and will depend on the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business opportunities providing desirable rates of return. We intend to finance our capital expenditures in a manner that will maintain our investment-grade credit ratings and capital structure.
CASH FLOWS FROM FINANCING ACTIVITIES
| CASH FLOWS FROM FINANCING ACTIVITIES |
| (Dollars in millions) |
| | 2014 | 2014 change | 2013 | 2013 change | 2012 |
| Sempra Energy Consolidated | $ | 854 | $ | 516 | | | $ | 338 | $ | (1,017) | | | $ | 1,355 |
| SDG&E | | 10 | | (184) | | | | 194 | | 2 | | | | 192 |
| SoCalGas | | 397 | | 406 | | | | (9) | | 147 | | | | (156) |
Sempra Energy Consolidated
Cash provided by financing activities at Sempra Energy increased in 2014 primarily due to:
| § | $1.2 billion higher issuances of debt, including an increase in issuances of long-term debt of $373 million ($2 billion in 2014 compared to $1.6 billion in 2013) and an increase in commercial paper and other short-term debt with maturities greater than 90 days of $818 million ($1.3 billion increase in 2014 compared to $445 million in 2013); and |
| § | $412 million increase in short-term debt in 2014 compared to $256 million in 2013; offset by |
| § | $574 million net proceeds received in 2013 from the sale of noncontrolling interests at Sempra Mexico; and |
| § | $246 million higher payments on debt, including higher payments of long-term debt of $219 million ($1.2 billion in 2014 compared to $984 million in 2013), and higher payments of commercial paper and other short-term debt with maturities greater than 90 days of $27 million ($831 million in 2014 compared to $804 million in 2013). |
Cash provided by financing activities in 2013 compared to 2012 decreased due to:
| § | $1 billion lower issuances of debt, including a decrease in issuances of long-term debt of $631 million ($1.6 billion in 2013 compared to $2.2 billion in 2012) and a decrease in issuances of commercial paper and other short-term debt with maturities greater than 90 days of $385 million ($445 million in 2013 compared to $830 million in 2012); |
| § | $661 million higher payments on long-term debt ($984 million in 2013 compared to $323 million in 2012), excluding amounts related to commercial paper with maturities greater than 90 days; |
| § | $83 million redemption of SDG&E’s outstanding preferred stock (including call premium and accrued dividends); and |
| § | $56 million increase in common stock dividends paid primarily due to an increase in the dividend rate; offset by |
| § | $574 million net proceeds received from the sale of noncontrolling interests at Sempra Mexico; and |
| § | $256 million increase in short-term debt in 2013 compared to $47 million decrease in 2012. |
SDG&E
The cash provided by financing activities at SDG&E decreased in 2014 primarily due to:
| § | $350 million lower issuance of long-term debt; and |
| § | $200 million common stock dividends paid in 2014; offset by |
| § | $175 million lower payments on long-term debt; and |
| § | $128 million higher increase in short-term debt. |
Cash provided by financing activities at SDG&E increased in 2013 compared to 2012 primarily due to:
| § | $201 million higher issuances of long-term debt; |
| § | $59 million increase in short-term debt in 2013; and |
| § | $14 million reduction in capital distributions made by Otay Mesa VIE ($26 million in 2013 compared to $40 million in 2012); offset by |
| § | $83 million redemption of outstanding preferred stock (including call premium and accrued dividends); and |
| § | $189 million higher payments on long-term debt. |
SoCalGas
At SoCalGas, financing activities were a net source of cash in 2014 compared to a use of cash in 2013, primarily due to:
| § | $747 million net proceeds from the issuance of long-term debt in 2014; offset by |
| § | $250 million payment of long-term debt in 2014; |
| § | $50 million increase in common stock dividends paid ($100 million in 2014 compared to $50 million in 2013); and |
| § | $34 million lower increase in short-term debt. |
Cash used by financing activities at SoCalGas in 2013 compared to 2012 decreased primarily due to:
| § | $250 million repayment of long-term debt in 2012; |
| § | $200 million reduction in common stock dividends paid ($50 million in 2013 compared to $250 million in 2012); and |
| § | $42 million increase in short-term debt in 2013; offset by |
| § | $348 million issuance of long-term debt in 2012. |
Long-term debt balances at December 31 were
| LONG-TERM DEBT(1) | | | | | | |
| (Dollars in millions) | | | | | | |
| | At December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 12,636 | $ | 12,400 | $ | 12,346 |
| SDG&E | | 4,684 | | 4,554 | | 4,308 |
| SoCalGas | | 1,906 | | 1,411 | | 1,413 |
| (1) Includes the current portion of long-term debt. | | | | |
At December 31, 2014, the following information applies to long-term debt:
| | Sempra Energy | | | | |
| | Consolidated | SDG&E | SoCalGas |
| Weighted average life to maturity, in years | 12.8 | | 16.1 | | 18.7 | |
| Weighted average interest rate | 4.79 | % | 4.71 | % | 4.39 | % |
Issuances of Long-Term Debt
Major public issuances of long-term debt over the last three years include the following:
| ISSUANCES OF LONG-TERM DEBT |
| (Dollars in millions) | | | | | | |
| | | Amount | | Rate | | Maturing |
| | | | | | | | |
| Sempra Energy | | | | | | |
| | Notes, June 2014 | $ | 500 | | 3.55 | % | 2024 |
| | Notes, November 2013 | | 500 | | 4.05 | | 2023 |
| | Notes, September 2012 | | 500 | | 2.875 | | 2022 |
| | Notes, March 2012 | | 600 | | 2.30 | | 2017 |
| | | | | | | | |
| Sempra Mexico | | | | | | |
| | Notes, February 2013 | | 100 | | 2.66 | | 2018 |
| | Notes, February 2013 | | 298 | | 4.12 | | 2023 |
| | | | | | | | |
| SDG&E | | | | | | |
| | 366-day commercial paper, May 2014 | | 100 | | 0.40 | | 2015 |
| | First mortgage bonds, September 2013 | | 450 | | 3.60 | | 2023 |
| | First mortgage bonds, March 2012 | | 250 | | 4.30 | | 2042 |
| | | | | | | | |
| SoCalGas | | | | | | |
| | First mortgage bonds, September 2014 | | 500 | | 3.15 | | 2024 |
| | First mortgage bonds, March 2014 | | 250 | | 4.45 | | 2044 |
| | First mortgage bonds, September 2012 | | 350 | | 3.75 | | 2042 |
Sempra Energy used the proceeds from its issuances of long-term debt primarily for general corporate purposes and to repay commercial paper. We discuss issuances of long-term debt further in Note 5 of the Notes to Consolidated Financial Statements.
The California Utilities used the proceeds from their issuances of long-term debt:
| § | for general working capital purposes; |
| § | to support their electric (at SDG&E) and natural gas (SDG&E and SoCalGas) procurement programs; |
| § | to redeem all outstanding shares of SDG&E’s preferred stock; |
| § | to repay commercial paper at SDG&E; and |
| § | to replenish amounts expended and fund future expenditures for the expansion and improvement of their utility plants. |
Payments on Long-Term Debt
Payments on long-term debt in 2014 included
| § | $500 million of Sempra Energy’s 2-percent notes due in 2014 |
| § | $300 million of Sempra Energy’s notes at variable rates (1.01 percent at December 31, 2013) due in 2014 |
| § | $250 million of SoCalGas’ 5.5-percent notes due in 2014 |
| § | $62 million of 5.1-percent to 6.75-percent Luz del Sur bank loans maturing in 2015 and 2016 |
| § | $54 million of 5.72-percent to 6.47-percent Series A Luz del Sur notes maturing in 2014 |
Payments on long-term debt in 2013 included
| § | $400 million of Sempra Energy’s 6-percent notes due in 2013 |
| § | $250 million of Sempra Energy’s 8.9-percent notes due in 2013, including $200 million at variable rates after fixed-to-floating interest rate swaps |
| § | $60 million of SDG&E’s 5.85-percent Pollution Control Revenue Bonds (PCRBs) due in 2021 |
| § | $115 million of SDG&E’s 5.9-percent PCRBs due in 2014 |
| § | $14 million of SDG&E’s 6.8-percent PCRBs due in 2015 |
| § | $86 million of 2.75-percent Series A Chilean public bonds maturing in 2014 |
Payments on long-term debt in 2012 included $250 million of SoCalGas 4.8-percent first mortgage bonds at maturity in October 2012.
In Note 5 of the Notes to Consolidated Financial Statements, we provide information about our lines of credit and additional information about debt activity.
CAPITAL STOCK TRANSACTIONS
Sempra Energy
Cash provided by employee stock option exercises and newly issued shares for our dividend reinvestment and 401(k) saving plans was
SDG&E
In 2013, SDG&E redeemed all of its outstanding preferred stock for $83 million (including call premium and accrued dividends). We discuss the redemption in Note 11 of the Notes to Consolidated Financial Statements.
DIVIDENDS
Sempra Energy
Sempra Energy paid cash dividends on common stock of:
In 2014, dividends declared increased due to an increase in the per-share quarterly dividend from $0.63 in 2013 to $0.66 in 2014. Offsetting this increase was a decrease in cash paid to fund dividends in 2014 compared to 2013 due to the issuance of new common shares to fund the dividend requirements of our savings plans and common stock purchase plan. The increase in 2013 was due to an increase in the per-share quarterly dividend from $0.60 in 2012 to $0.63 in 2013.
On December 9, 2014, Sempra Energy declared a quarterly dividend of $0.66 per share of common stock that was paid on January 15, 2015. We provide additional information about Sempra Energy dividends above in “Capital Resources and Liquidity – Overview – Sempra Energy Consolidated.”
SDG&E
In 2014, SDG&E paid dividends to Enova and Enova paid corresponding dividends to Sempra Energy of $200 million. SDG&E did not pay any common dividends to Sempra Energy in 2013 or 2012 to preserve cash to fund its capital expenditures program, which included the Sunrise Powerlink.
Enova, a wholly owned subsidiary of Sempra Energy, owns all of SDG&E’s outstanding common stock. Accordingly, dividends paid by SDG&E to Enova and dividends paid by Enova to Sempra Energy are both eliminated in Sempra Energy’s Consolidated Financial Statements.
SoCalGas
SoCalGas paid dividends to Pacific Enterprises (PE) and PE paid corresponding dividends to Sempra Energy of:
PE, a wholly owned subsidiary of Sempra Energy, owns all of SoCalGas’ outstanding common stock. Accordingly, dividends paid by SoCalGas to PE and dividends paid by PE to Sempra Energy are both eliminated in Sempra Energy’s Consolidated Financial Statements.
DIVIDEND RESTRICTIONS
The board of directors for each of Sempra Energy, SDG&E and SoCalGas has the discretion to determine the payment and amount of future dividends by each such entity. The CPUC’s regulation of SDG&E’s and SoCalGas’ capital structures limits the amounts that are available for loans and dividends to Sempra Energy. At December 31, 2014, based upon these regulations, Sempra Energy could have received combined loans and dividends of approximately $755 million from SoCalGas and approximately $640 million from SDG&E.
We provide additional information about restricted net assets in Note 1 of the Notes to Consolidated Financial Statements.
CAPITALIZATION
| TOTAL CAPITALIZATION AND DEBT-TO-CAPITALIZATION RATIOS |
| (Dollars in millions) |
| | | December 31, 2014 |
| | | Sempra Energy | | | | | | | |
| | | Consolidated(1) | | SDG&E(1) | | SoCalGas | |
| Total capitalization | $ | 26,469 | | $ | 9,922 | | $ | 4,737 | |
| Debt-to-capitalization ratio | | 54 | % | | 50 | % | | 41 | % |
| | | | | | | | | | | |
| | | December 31, 2013 |
| | | Sempra Energy | | | | | | | |
| | | Consolidated(1) | | SDG&E(1) | | SoCalGas | |
| Total capitalization | $ | 24,795 | | $ | 9,332 | | $ | 4,002 | |
| Debt-to-capitalization ratio | | 52 | % | | 49 | % | | 36 | % |
| (1) | Includes noncontrolling interest and debt of Otay Mesa Energy Center LLC with no significant impact. |
Significant changes during 2014 that affected capitalization include the following:
| § | Sempra Energy Consolidated: net increases in debt, primarily commercial paper borrowings, partially offset by comprehensive income exceeding dividends |
| § | SDG&E: increase in both long-term and short-term debt, partially offset by comprehensive income exceeding dividends |
| § | SoCalGas: an increase in long-term debt, partially offset by comprehensive income exceeding dividends |
We provide additional information about these significant changes in Notes 1 and 5 of the Notes to Consolidated Financial Statements.
The following tables summarize principal contractual commitments, primarily long-term, at December 31, 2014 for Sempra Energy Consolidated, SDG&E and SoCalGas. We provide additional information about commitments above and in Notes 5, 7 and 15 of the Notes to Consolidated Financial Statements.
| PRINCIPAL CONTRACTUAL COMMITMENTS OF SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | 2015 | 2016 and 2017 | 2018 and 2019 | Thereafter | Total |
| Long-term debt | $ | 456 | $ | 1,543 | $ | 1,881 | $ | 8,467 | $ | 12,347 |
| Interest on long-term debt(1) | | 583 | | 1,059 | | 874 | | 5,082 | | 7,598 |
| Operating leases | | 73 | | 129 | | 107 | | 271 | | 580 |
| Capital leases | | 6 | | 8 | | 10 | | 211 | | 235 |
| Purchased-power contracts | | 674 | | 1,351 | | 1,468 | | 7,363 | | 10,856 |
| Natural gas contracts | | 432 | | 801 | | 492 | | 253 | | 1,978 |
| LNG contract(2) | | 381 | | 1,168 | | 1,375 | | 7,603 | | 10,527 |
| Construction commitments | | 721 | | 139 | | 11 | | 6 | | 877 |
| Build-to-suit lease | | 4 | | 20 | | 20 | | 267 | | 311 |
| SONGS decommissioning | | 116 | | 137 | | 119 | | 341 | | 713 |
| Sunrise Powerlink wildfire mitigation fund | | 3 | | 7 | | 7 | | 302 | | 319 |
| Other asset retirement obligations | | 26 | | 59 | | 49 | | 1,343 | | 1,477 |
| Pension and other postretirement benefit | | | | | | | | | | |
| obligations(3) | | 42 | | 276 | | 388 | | 959 | | 1,665 |
| Environmental commitments | | 29 | | 22 | | 3 | | 11 | | 65 |
| Other | | 42 | | 31 | | 23 | | 64 | | 160 |
| Totals | $ | 3,588 | $ | 6,750 | $ | 6,827 | $ | 32,543 | $ | 49,708 |
| (1) | We calculate expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. We calculate expected interest payments for variable-rate obligations, including fixed-to-floating interest rate swaps, based on forward rates in effect at December 31, 2014. |
| (2) | Sempra Natural Gas has a purchase agreement with a major international company for the supply of LNG to the Energía Costa Azul terminal. The multi-year agreement is priced using a predetermined formula based on natural gas market indices. The expected payments under the contract are based on forward prices of the applicable market index from 2015 to 2024 and an estimated one percent escalation per year after 2024. We provide more information about this contract in Note 15 of the Notes to Consolidated Financial Statements. |
| (3) | Amounts represent expected company contributions to the plans for the next 10 years. |
| PRINCIPAL CONTRACTUAL COMMITMENTS OF SDG&E |
| (Dollars in millions) |
| | | 2015 | 2016 and 2017 | 2018 and 2019 | Thereafter | Total |
| Long-term debt | $ | 360 | $ | 20 | $ | 456 | $ | 3,625 | $ | 4,461 |
| Interest on long-term debt(1) | | 204 | | 385 | | 368 | | 2,468 | | 3,425 |
| Operating leases | | 24 | | 46 | | 34 | | 75 | | 179 |
| Capital leases | | 5 | | 8 | | 10 | | 211 | | 234 |
| Purchased-power contracts | | 494 | | 987 | | 1,005 | | 6,318 | | 8,804 |
| Construction commitments | | 229 | | 94 | | 11 | | 6 | | 340 |
| SONGS decommissioning | | 116 | | 137 | | 119 | | 341 | | 713 |
| Sunrise Powerlink wildfire mitigation fund | | 3 | | 7 | | 7 | | 302 | | 319 |
| Other asset retirement obligations | | 4 | | 6 | | 6 | | 144 | | 160 |
| Pension and other postretirement benefit | | | | | | | | | | |
| obligations(2) | | 12 | | 65 | | 106 | | 238 | | 421 |
| Environmental commitments | | 13 | | 4 | | 1 | | 9 | | 27 |
| Totals | $ | 1,464 | $ | 1,759 | $ | 2,123 | $ | 13,737 | $ | 19,083 |
| (1) | SDG&E calculates expected interest payments using the stated interest rate for fixed-rate obligations, including floating-to-fixed interest rate swaps. |
| (2) | Amounts represent expected company contributions to the plans for the next 10 years. |
| PRINCIPAL CONTRACTUAL COMMITMENTS OF SOCALGAS |
| (Dollars in millions) |
| | | 2015 | 2016 and 2017 | 2018 and 2019 | Thereafter | Total |
| Long-term debt | $ | ― | $ | 8 | $ | 250 | $ | 1,655 | $ | 1,913 |
| Interest on long-term debt(1) | | 84 | | 167 | | 144 | | 1,193 | | 1,588 |
| Natural gas contracts | | 149 | | 243 | | 142 | | 123 | | 657 |
| Operating leases | | 39 | | 70 | | 64 | | 156 | | 329 |
| Capital leases | | 1 | | ― | | ― | | ― | | 1 |
| Construction commitments | | 218 | | 42 | | ― | | ― | | 260 |
| Environmental commitments | | 4 | | 17 | | 1 | | 2 | | 24 |
| Pension and other postretirement benefit | | | | | | | | | | |
| obligations(2) | | 2 | | 167 | | 224 | | 605 | | 998 |
| Asset retirement obligations | | 21 | | 53 | | 43 | | 1,159 | | 1,276 |
| Totals | $ | 518 | $ | 767 | $ | 868 | $ | 4,893 | $ | 7,046 |
| (1) | SoCalGas calculates interest payments using the stated interest rate for fixed-rate obligations. |
| (2) | Amounts represent expected company contributions to the plans for the next 10 years. |
The tables exclude
| § | contracts between consolidated affiliates |
| § | individual contracts that have annual cash requirements less than $1 million |
The tables also exclude income tax liabilities of
| § | $48 million for Sempra Energy Consolidated |
| § | $19 million for SoCalGas |
These liabilities relate to uncertain tax positions and were excluded from the tables because we are unable to reasonably estimate the timing of future payments due to uncertainties in the timing of the effective settlement of tax positions. We provide additional information about unrecognized tax benefits in Note 6 of the Notes to Consolidated Financial Statements.
OFF-BALANCE SHEET ARRANGEMENTS
The maximum aggregated amount of guarantees provided by Sempra Energy on behalf of related parties at December 31, 2014 is $4.5 billion. We discuss these guarantees in Notes 4, 5 and 15 of the Notes to Consolidated Financial Statements.
SDG&E has entered into power purchase arrangements which are variable interests. We discuss variable interests in Note 1 of the Notes to Consolidated Financial Statements.
The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels in 2014. At December 31, 2014, Sempra Energy’s unsecured debt rating remained at BBB+ with a stable outlook. In January 2014, Moody’s increased SDG&E’s and SoCalGas’ unsecured debt rating to A1 with a stable outlook.
Sempra Energy, SDG&E and SoCalGas have committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes. Borrowings under these facilities bear interest at benchmark rates plus a margin that varies with market index rates and each borrower’s credit rating. Each facility also requires a commitment fee on available unused credit.
Under these committed lines, if Sempra Energy were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 25 to 50 basis points, depending on the severity of the downgrade. The commitment fee on available unused credit would also increase 5 to 10 basis points, depending on the severity of the downgrade.
Under these committed lines, if SDG&E or SoCalGas were to experience a ratings downgrade from its current level, the rate at which borrowings bear interest would increase by 12.5 to 87.5 basis points, depending on the severity of the downgrade. The commitment fee on available unused credit would also increase 2.5 to 20 basis points, depending on the severity of the downgrade. The January 2014 upgrade of the California Utilities’ credit ratings reduced the interest rate and commitment fee rate on committed lines of credit by 12.5 basis points and 2.5 basis points, respectively.
For Sempra Energy and SDG&E, their credit ratings may affect credit limits related to derivative instruments, as we discuss in Note 9 of the Notes to Consolidated Financial Statements.
FACTORS INFLUENCING FUTURE PERFORMANCE
The California Utilities’ operations have historically provided relatively stable earnings and liquidity.
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 Notes 13 and 14 of the Notes to Consolidated Financial Statements.
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 (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 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. As a result of on-going efforts since this original filing, the California Utilities have been able to eliminate over two hundred miles of pipeline from the testing scope and have revised their total estimated cost for Phase 1 to $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). 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.
In June 2014, the CPUC issued a final decision in the Triennial Cost Allocation Proceeding (TCAP) addressing SDG&E’s and SoCalGas’ PSEP that approved the utilities’ model for implementing PSEP, and established the criteria to determine the amounts related to PSEP that may be recovered from ratepayers and the processes for recovery of such amounts, including providing that such costs are subject to a reasonableness review.
As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2014, SDG&E and SoCalGas have recorded PSEP costs of $2 million and $85 million, respectively, in the CPUC-authorized regulatory account. In October 2014, SDG&E and SoCalGas filed a request with the CPUC for authority to recover PSEP costs from customers as incurred, subject to refund pending the results of a reasonableness review by the CPUC. In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. We requested a decision in 2015.
In July 2014, the CPUC Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN alleged that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision.
If the CPUC were to decide as part of any future reasonableness review that rate recovery not be allowed for certain gas pipeline safety costs incurred by SDG&E and SoCalGas, or if the CPUC were to decide in favor of the ORA/TURN joint application for rehearing, it could materially adversely affect the respective company’s cash flows, financial condition, results of operations and prospects in implementing the PSEP.
We provide additional information in Note 14 of the Notes to Consolidated Financial Statements.
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. In December 2014, the CPUC adopted an electric safety enforcement program whereby electric utilities may be cited by CPUC staff for violations of the CPUC’s safety requirements or federal standards.
In December 2011, the CPUC adopted a gas safety citation program whereby natural gas distribution companies can be cited by CPUC staff for violations of the CPUC’s safety standards. In September 2013, the CPUC’s safety and enforcement division issued its Standard Operating Procedures setting forth its principles and management process for the natural gas safety citation program.
Under each enforcement program, each day of an ongoing violation may be counted as an additional offense. The maximum penalty is $50,000 per offense. Citations under either program may be appealed to the CPUC. The CPUC plans to make further refinements to the electric and gas safety enforcement programs in 2015.
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 have exceeded its liability insurance coverage and amounts 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 December 31, 2014, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets include assets of $373 million in Other Regulatory Assets (long-term), of which $366 million is related to CPUC-regulated operations and $7 million is related to FERC-regulated operations, for costs incurred and the estimated settlement of pending claims. Recovery of these costs 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 December 31, 2014, the resulting after-tax charge against earnings would have been up to approximately $217 million. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements.
We provide additional information concerning these matters in Notes 14 and 15 of the Notes to Consolidated Financial Statements.
SONGS
We discuss regulatory and other matters related to SONGS in the Notes to Consolidated Financial Statements as follows:
In Note 13:
| § | SONGS Outage and Retirement |
| § | Settlement Agreement to Resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS Outage (SONGS OII) |
| § | Nuclear Regulatory Commission Proceedings |
| § | Nuclear Decommissioning and Funding |
| § | Nuclear Decommissioning Trusts |
In Note 15:
| § | Legal Proceedings – SDG&E – Lawsuit Against Mitsubishi Heavy Industries, Ltd. |
| § | U.S. Department of Energy (DOE) Nuclear Fuel Disposal |
We also discuss SONGS in “Risk Factors” in our 2014 Annual Report on Form 10-K.
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 15 of the Notes to Consolidated Financial Statements.
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-CARE (California Alternate Rates for Energy) residential customers and up to a $5.00 monthly fixed charge for CARE customers. Beginning January 1, 2016, the maximum allowable fixed charge may be adjusted by no more than the annual percentage increase in the Consumer Price Index for the prior calendar year. In February 2014, SDG&E filed comprehensive proposals with the CPUC that provide a roadmap to reforming electric residential rate design beginning in 2015 and continuing through 2018, consistent with the provisions of AB 327. We expect a CPUC decision in the first half of 2015.
In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing net energy metering (NEM) program pursuant to the provisions of AB 327 that require the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of SB 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of one megawatt or less may choose to participate in the NEM program. Under NEM, customer-generators receive a full retail-rate bill credit for the power they generate that is fed back to the utility’s power grid during times when the customer’s generation exceeds their own energy usage.
Meaningful rate reform is necessary to ensure that SDG&E is authorized to recover, from NEM customers, the costs incurred in providing services to NEM customers 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 allow it to recover costs associated with the services provided to NEM customers and better align electric residential rates with the costs that are incurred to provide service, 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 2014 Annual Report on Form 10-K.
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 14 of the Notes to Consolidated Financial Statements.
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.”
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 $834 million in goodwill on its Consolidated Balance Sheet at December 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.
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, foreign currency rate fluctuations 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. This resulted in immaterial changes in rates. The sub-transmission rates period has been extended for one year, for one time only, to December 2015, due to a change in law issued in December 2014. Accordingly, the next review process for sub-transmission rates will be in January 2016, covering the period from January 2016 to December 2019.
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 September 2014, tax reform legislation was passed in Chile. The main amendments established in the tax reform include, among others, a gradual increase in the corporate income tax rate and the introduction of two options to pay the secondary tax (shareholder tax) on corporate profits (either immediate payment of tax or deferment of tax until earnings are distributed) with different impacts to the total income tax burden. We discuss this tax reform above in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes.”
In December 2014, the Peruvian government passed a tax reform law. Among other changes, the new law gradually reduces the 30 percent corporate tax rate in 2014 to 26 percent by 2019 with an offsetting increase in the withholding tax rate on dividends. We discuss this tax reform above in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes.”
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 the first half of 2015.
Transmission Projects
Chilquinta Energía. Chilquinta Energía has 50-percent ownership in two 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 projects will cost approximately $150 million in total and be completed in 2016 and 2017.
In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 60 miles, and we estimate the projects will cost approximately $80 million in total and be completed in 2018.
Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A. totaling $40 million at December 31, 2014 to provide project financing for the construction of transmission lines. Eletrans S.A. is an affiliate of Chilquinta Energía. We discuss this loan in Note 1 of the Notes to Consolidated Financial Statements.
The projects will be financed by the joint venture partners. Other financing may be pursued upon completion of the projects.
Luz del Sur. Luz del Sur has received regulatory approval for an amended transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima. We estimate that the project will cost approximately $150 million and be in service in 2016 and 2017 as portions are completed. Once in operation, the capitalized cost will earn the regulated return for 30 years. The project will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.
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, securities issuances, project financing, and partnering in joint ventures.
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 1 of the Notes to Consolidated Financial Statements. The shares sold represent approximately 18.9 percent of the ownership interests in IEnova, which reduces our earnings from Sempra Mexico and has a dilutive effect on our earnings per share. The earnings attributable to IEnova’s noncontrolling interests were $47 million and $26 million for the years ended December 31, 2014 and 2013, respectively.
In June and August 2014, IEnova entered into three-year term corporate revolving credit facility agreements for $200 million and $100 million, respectively, to finance working capital and for other general corporate purposes. IEnova drew down $145 million in 2014 from the first facility, and $51 million in 2014 from the second facility. We discuss the credit facilities further in Note 5 of the Notes to Consolidated Financial Statements.
We discuss the impact of Mexican tax reform in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.
Pipeline Projects
In October 2012, IEnova was awarded two contracts by the 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. A section of the project was completed in October 2014. We expect to complete the remaining sections in stages in 2015 and 2016. The capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars. IEnova continues to monitor CFE project opportunities and carefully analyze CFE bids in order to participate in those that fit its overall growth strategy.
In December 2012, through its joint venture with PEMEX, the Mexican state-owned oil company, IEnova 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. PEMEX has fully contracted the capacity 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 would be developed by IEnova’s joint venture with PEMEX. The project is a 70-mile natural gas pipeline with two compression stations, 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. The pipeline began operations at the end of 2014.
In addition, in 2014, IEnova’s 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 $1.3 billion to $1.5 billion. IEnova’s joint venture with PEMEX has a 50-percent interest in the project. In June 2014, the project executed an engineering, procurement and construction contract, and in July 2014, the project issued the full notice to proceed. 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. The pipeline’s 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 2014, Sempra Mexico made loans to affiliates of its joint venture with PEMEX totaling $123 million at December 31, 2014. We discuss these loans in Note 1 of the Notes to Consolidated Financial Statements.
In December 2014, Sempra Mexico entered into the Ojinaga pipeline natural gas transportation services agreement with CFE for a 25-year term. CFE contracted 100-percent of the transport capacity of the Ojinaga pipeline, equal to 1.4 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 127-mile, 42-inch pipeline, with an estimated cost of $300 million. We expect the pipeline to begin operations in the first half of 2017.
Energía Sierra Juárez
In October 2013, Sempra Mexico started construction on the 155-MW first phase of the Energía Sierra Juárez wind generation project, which first phase is fully contracted by SDG&E. The Energía Sierra Juárez project is designed to provide up to 1,200 MW of capacity if fully developed.
In June 2014, the Energía Sierra Juárez wind project entered into an 18-year, $240 million loan to project finance the construction and drew down $82 million under the loan agreement, as we discuss in Note 5 of the Notes to Consolidated Financial Statements. The loan agreement also provides for a $31.7 million letter of credit facility. Energía Sierra Juárez also entered into a separate Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project.
In July 2014, after obtaining the required regulatory approvals in Mexico and the U.S., we consummated the sale of a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. for $24 million, net of $2 million cash returned in the project, as we discuss in Note 3 of the Notes to Consolidated Financial Statements. Upon consummation of the sale, the debt under the credit facilities was deconsolidated.
Future expansion of Energía Sierra Juárez will depend, among other factors, on the ability to obtain additional power purchase contracts.
Energía Costa Azul LNG Terminal
In February 2015, Sempra Natural Gas, IEnova, and a subsidiary of PEMEX entered into a Memorandum of Understanding (MOU) to collaborate in the development of a natural gas liquefaction project at IEnova’s existing regasification terminal at Energía Costa Azul. The MOU defines the basis for the parties to explore PEMEX’s participation in this potential liquefaction project, including joining efforts on its development and structuring agreements that would allow opportunities for PEMEX to become a customer, natural gas supplier and investor.
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 electric load serving entities, which provide electric service to end-users and wholesale customers. 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.
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 began construction on the 75-MW wind farm in 2013, and the facility achieved commercial operation in October 2014. Nebraska Public Power District has contracted for all of the wind energy from the project for 25 years. In October 2014, Sempra Renewables completed a private offering of an aggregate of $72 million in principal amount of 4.82-percent fixed-rate notes maturing in 2039. Proceeds from this offering were used to finance this project. In November 2014, we completed a sale of 50 percent of our equity in Broken Bow 2 Wind to ConEdison Development and the debt was deconsolidated as we discuss in Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements.
California Solar Partnership with ConEdison Development
In May 2014, Sempra Renewables and ConEdison Development consummated an agreement to partner in four solar projects in California. The joint venture includes 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. Sempra Renewables and ConEdison Development each own a 50-percent interest in the four fully operating solar facilities. We discuss the joint venture further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
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 550 MW of solar power; it is being developed in multiple phases as power sales become contracted. Copper Mountain Solar is comprised of four separate projects.
Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, which is fully contracted for 20 years to PG&E.
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 and 4 of the Notes to Consolidated Financial Statements.
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 in 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 Notes 3, 4 and 5 of the Notes to Consolidated Financial Statements.
In July 2014, Sempra Renewables signed a 20-year power sale agreement with Southern California Edison for all of the solar power from Copper Mountain Solar 4 beginning in 2020. We expect Copper Mountain Solar 4 to be in service in 2016, marketing its output prior to the commencement of the power sale agreement. Copper Mountain Solar 4 will total 94 MW when completed. The power sale agreement is subject to approval by the CPUC.
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, which is fully contracted for 20 years to PG&E, was completed in December 2012. 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 and 4 of the Notes to Consolidated Financial Statements.
Sempra Natural Gas
Mesquite Power Natural Gas-Fired Plant
In June 2011, Sempra Natural Gas entered into a 25-year power contract with various members of 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 or other sources 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 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. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining block of the power plant and assign the SPPR Group contract to the buyer. We anticipate the sale will close in the first half of 2015, subject to obtaining third-party consents for the assignment of the SPPR Group contract. We discuss the plan to sell the second 625-MW block of Mesquite Power in Note 3 of the Notes to Consolidated Financial Statements.
Rockies Express
Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (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. All of REX’s original capacity sales provide for west-to-east service. Sempra Natural Gas has an agreement for such capacity on REX through November 2019. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013. Contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express.
In November 2013, FERC issued a decision ruling that east-to-west service offerings within a single REX rate zone would not result in potential rate reductions under provisions in the original customers’ west-to-east contracts (“most favored nation” provisions). In December 2013, certain west-to-east customers sought rehearing of that decision. In 2014, Rockies Express reached settlements with three west-to-east customers, with one customer continuing to seek rehearing. The triggering of these provisions would result in significantly reduced revenue to REX from these west-to-east contracts.
In April 2014, prior to the launching of an open season, Rockies Express had secured binding financial commitments with four shippers totaling 1.2 Bcf per day of capacity for east-to-west transportation services at a rate of $0.50 per dekatherm for a term of 20 years originating at or near Clarington, Ohio. We expect the capacity to be in service by mid-2015. In June 2014, Rockies Express finished constructing the Seneca Lateral, an initial 0.25 Bcf per day capacity project that connects natural gas production sources in Ohio to REX. The lateral’s capability was further expanded to 0.6 Bcf per day of capacity in January 2015. The lateral is fully contracted through September 2021. Rockies Express has also conducted a non-binding open season to assess further expansion of its facilities for east-to-west service. The expansion would require additional capital investment and would be subject to regulatory approval.
Sempra Natural Gas expects to invest approximately $110 million in Rockies Express to repay project debt maturing in early 2015.
Our carrying value in Rockies Express at December 31, 2014 is $340 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.
REX experienced a rupture on January 29, 2015. There were no injuries, nor was fire involved. This incident occurred near Bowling Green, Missouri, which is the western end of REX Zone 3 in Segment 300. It has been determined that a weld failed, the cause of which is still under investigation. Rockies Express returned Segment 300 to service on February 8, 2015, and is fully cooperating with the Pipeline and Hazardous Materials Safety Administration.
Natural Gas Storage
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, LLC (LA Storage) in Louisiana. LA Storage could be 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. In addition, our LA Storage development project may be unable to attract cash flow commitments sufficient to support further investment, or unable to extend its FERC construction permit beyond its expiration date of June 2015. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage Pipeline, that is uncontracted. We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. 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 the book value is in excess of the fair value, we would record a non-cash impairment charge. The book value of our equity in natural gas storage assets at December 31, 2014 is $1.3 billion, excluding intercompany loans to the projects totaling approximately $250 million.
After placing additional capacity in service at Bay Gas and Mississippi Hub in June 2014, Sempra Natural Gas has 42 Bcf of operational working natural gas storage capacity (20 Bcf at Bay Gas and 22 Bcf at Mississippi Hub). Sempra Natural Gas may, over the long term, develop additional storage capacity at its facilities.
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
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 will utilize the terminal’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 Bcf per day. The current project is comprised of three liquefaction trains 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 the project to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, but excluding capitalized interest and other financing costs. The majority of the incremental investment 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 $10 billion.
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., providing for each of them to acquire a 16.6 percent equity interest in Cameron LNG Holdings, the joint venture holding company for the liquefaction project, and for Sempra Energy to retain a 50.2-percent equity interest in the joint venture. As we discuss below, on October 1, 2014, we contributed our share of equity to the joint venture through the contribution of Cameron LNG. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash.
Also in May 2013, Cameron LNG 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 one third of the total production of the first three trains.
In June and November 2013, Sempra Natural Gas signed agreements totaling 1.45 Bcf per day of firm natural gas transportation service to the Cameron LNG facilities on the Cameron Interstate Pipeline 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.
In January 2012, the DOE approved Cameron LNG’s application for authorization to export LNG to Free Trade Agreement countries. In September 2014, the DOE granted Cameron LNG final authorization to export from its Cameron liquefaction project approximately 1.7 Bcf per day of domestically produced LNG to countries with which the United States does not have agreements for free trade in natural gas (Non-Free Trade Agreement). This authorization is for a 20-year term commencing on the earlier of the date of first commercial export or seven years from the date of the authorization. Under the terms of the authorization, Cameron LNG is authorized to export LNG either on its own behalf or as agent for the customers of the project.
In March 2014, an EPC contract was signed 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.
Between April and July 2014, FERC issued the Final Environmental Impact Statement for the project and issued orders authorizing the siting, construction and operation of the three-train liquefaction facility, as well as Cameron Interstate Pipeline’s 21-mile, 42-inch natural gas pipeline expansion, new compressor station and ancillary equipment that will provide natural gas transportation to the Cameron LNG facility. The joint venture issued full notice to proceed to the contractor in October 2014.
On August 6, 2014, Sempra Energy and each of the project partners provided their respective final investment decision with respect to the Cameron LNG Holdings joint venture, and the effective date of the joint venture occurred on October 1, 2014 after satisfaction of various conditions, including receipt of final regulatory approval and satisfaction of conditions precedent to the first disbursement of the project financing. Following the joint venture effective date, Cameron LNG is no longer wholly owned by Sempra Energy, and as of October 1, 2014, Sempra Energy began accounting for its investment in the joint venture under the equity method.
Also on August 6, 2014, Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG liquefaction project. Concurrently, Sempra Energy entered into completion guarantees under which it has severally guaranteed 50.2 percent of the debt, or a maximum of $3.7 billion. The project financing and completion guarantees became effective on October 1, 2014, and will terminate upon financial completion of the project, which will occur upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantees to be terminated in the second half of 2019.
Large-scale construction projects like the design, development and construction of the Cameron LNG liquefaction facility involve numerous risks and uncertainties, including among others, the potential for unforeseen engineering problems, substantial construction delays and increased costs. As noted above, Cameron LNG Holdings has entered into a turnkey EPC contract with a joint venture between CB&I Shaw Constructors, Inc. and Chiyoda International Corporation. If the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG Holdings would be required to engage a substitute contractor, which would result in project delays and increased costs, which could be significant. For a discussion of these risks and other risks relating to the development of the Cameron LNG liquefaction project that could adversely affect our future performance, see “Risk Factors” in our Annual Report on Form 10-K.
Cameron LNG Holdings has a terminal services agreement with one customer that requires the customer to pay capacity reservation and usage fees to use the Cameron LNG facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this services agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG’s EPC contractor on October 9, 2014, we expect this termination date to occur during the first half of 2017.
In December 2014, Cameron LNG Holdings filed with the DOE for authorization to match the total export volumes allowed to be exported to FTA countries under the FERC permit. This would allow for increased export from the three-train facility of up to 2.95 Mtpa. Cameron LNG Holdings expects to file the corresponding DOE Non-FTA permit application in the first quarter of 2015. Cameron LNG Holdings is also pursuing the permitting to expand the current configuration from the current three liquefaction trains. The expansion project is expected to include two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpa to 10 Mtpa, and one additional full containment LNG storage tank; a fourth tank was permitted with the base liquefaction project but not built. In February 2015, Cameron LNG Holdings filed the DOE FTA application and the pre-filing application at FERC for the two additional trains and one containment tank. The joint venture expects to file a corresponding DOE Non-FTA permit application before the end of 2015. Under the Cameron LNG financing agreements, expansion of the Cameron LNG facilities beyond the first three trains is subject to certain restrictions and conditions, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from lenders. Cameron LNG Holdings faces other risks and challenges with respect to a potential expansion of the facility, which are described in the “Risk Factors” section of our Annual Report on Form 10-K.
We discuss the deconsolidation of Cameron LNG, the Cameron LNG Holdings project financing obligations and Sempra Energy’s completion guarantee further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
Other LNG Liquefaction Development
Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at Sempra Mexico’s Energía Costa Azul facility and at our Port Arthur, Texas site. For these development projects, we have been meeting with potential customers and continue to see demand for LNG supplies in the 2020 to 2023 time frame.
We discuss Sempra Natural Gas’ participation in potential LNG liquefaction development at Sempra Mexico’s Energía Costa Azul facility above under “Sempra Mexico − Energía Costa Azul LNG Terminal.”
RBS Sempra Commodities
In three separate transactions in 2010 and one in early 2011, we and The Royal Bank of Scotland plc (RBS), our partner in the RBS Sempra Commodities joint venture, sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $71 million at December 31, 2014 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities under “Other Litigation” in Note 15 of the Notes to Consolidated Financial Statements. 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 15 of the Notes to Consolidated Financial Statements.
OTHER SEMPRA ENERGY MATTERS
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 “Market Risk – Foreign Currency Rate Risk” below. North American natural gas prices, when in decline, negatively affect profitability at Sempra Renewables and Sempra Natural Gas. In addition, an extended decline in current and forward projections of crude oil prices, coupled with slow economic growth, could cause a corresponding reduction in projected global demand for LNG. This could result in increased competition among those working on projects in an environment of declining LNG demand, such as the Sempra Energy-sponsored export initiatives. For a discussion of these risks and other risks involving changing natural gas and crude oil prices, see “Risk Factors” in our Annual Report on Form 10-K.
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 and transparency requirements 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 latter of which is pending final approval in 2015. 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 and extent of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate and may be restricted on the size of our hedging program.
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 14 and 15 of the Notes to Consolidated Financial Statements and in “Risk Factors” in our 2014 Annual Report on Form 10-K.
We describe legal proceedings that could adversely affect our future performance in Note 15 of the Notes to Consolidated Financial Statements.
Market risk is the risk of erosion of our cash flows, earnings, asset values and equity due to adverse changes in market prices, and interest and foreign currency rates.
Sempra Energy has policies governing its market risk management and trading activities. Sempra Energy and the California Utilities maintain separate and independent risk management committees, organizations and processes for the California Utilities and for all non-CPUC regulated affiliates to provide oversight of these activities. The committees consist of senior officers who establish policy, oversee energy risk management activities, and monitor the results of trading and other activities to ensure compliance with our stated energy risk management and trading policies. These activities include, but are not limited to, daily monitoring of market positions that create credit, liquidity and market risk. The respective oversight organizations and committees are independent from the energy procurement departments.
Along with other tools, we use Value at Risk (VaR) and liquidity metrics to measure our exposure to market risk associated with the commodity portfolios. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. A liquidity metric is intended to monitor the amount of financial resources needed for meeting potential margin calls as forward market prices move. VaR and liquidity risk metrics are calculated independently by the respective risk management oversight organizations.
The California Utilities use power and natural gas derivatives to manage natural gas and electric price risk associated with servicing load requirements. The use of power and natural gas derivatives is subject to certain limitations imposed by company policy and is in compliance with risk management and trading activity plans that have been filed with and approved by the CPUC. Any costs or gains/losses associated with the use of power and natural gas derivatives are considered to be commodity costs. Commodity costs are generally passed on to customers as incurred. However, SoCalGas is subject to incentive mechanisms that reward or penalize the utility for commodity costs below or above certain benchmarks.
We discuss revenue recognition in Note 1 of the Notes to Consolidated Financial Statements and the additional market-risk information regarding derivative instruments in Note 9 of the Notes to Consolidated Financial Statements.
We have exposure to changes in commodity prices, interest rates and foreign currency rates and exposure to counterparty nonperformance. The following discussion of these primary market-risk exposures as of December 31, 2014 includes a discussion of how these exposures are managed.
Market risk related to physical commodities is created by volatility in the prices and basis of certain commodities. Our various subsidiaries are exposed, in varying degrees, to price risk, primarily to prices in the natural gas and electricity markets. Our policy is to manage this risk within a framework that considers the unique markets and operating and regulatory environments of each subsidiary.
Segments within our Sempra International and Sempra U.S. Gas & Power operating units are generally exposed to commodity price risk indirectly through their LNG, natural gas pipeline and storage, and power generating assets and their power purchase agreements. Those segments may utilize commodity transactions in the course of optimizing these assets. These transactions are typically priced based on market indices, but may also include fixed price purchases and sales of commodities. Any residual exposure is monitored as described above.
The California Utilities’ market-risk exposure is limited due to CPUC-authorized rate recovery of the costs of commodity purchases, interstate and intrastate transportation, and storage activity. However, SoCalGas may, at times, be exposed to market risk as a result of incentive mechanisms that reward or penalize the utility for commodity costs below or above certain benchmarks for SoCalGas’ gas cost incentive mechanism, which we discuss in Note 14 of the Notes to Consolidated Financial Statements. If commodity prices were to rise too rapidly, it is likely that volumes would decline. This decline would increase the per-unit fixed costs, which could lead to further volume declines. The California Utilities manage their risk within the parameters of their market risk management framework. As of and for the year ended December 31, 2014, the total VaR of the California Utilities’ natural gas and electric positions was not material, and the procurement activities were in compliance with the procurement plans filed with and approved by the CPUC.
A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of our commodity-based financial derivatives as of December 31, 2014 and 2013. The impact of a change in energy commodity prices on our commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Also, the impact of a change in energy commodity prices on our commodity-based financial derivative instruments does not typically include the generally offsetting impact of our underlying asset positions.
We are exposed to fluctuations in interest rates primarily as a result of our having issued short- and long-term debt. Subject to regulatory constraints, we periodically enter into interest rate swap agreements to moderate our exposure to interest rate changes and to lower our overall costs of borrowing.
The table below shows the nominal amount and the one-year VaR for long-term debt at December 31, 2014 and 2013:
| NOMINAL AMOUNT AND ONE-YEAR VALUE AT RISK OF LONG-TERM DEBT(1) |
| (Dollars in millions) |
| | | Sempra Energy | | | | | | |
| | | Consolidated | | SDG&E | | SoCalGas |
| | | Nominal | One-year | | Nominal | One-year | | Nominal | One-year |
| | | debt | VaR(2) | | debt | VaR(2) | | debt | VaR(2) |
| At December 31, 2014 | | | | | | | | | | | | | | |
| California Utilities fixed-rate | $ | 6,049 | $ | 502 | | $ | 4,136 | $ | 341 | | $ | 1,913 | $ | 161 |
| California Utilities variable-rate | | 325 | | 13 | | | 325 | | 13 | | | ― | | ― |
| All other, fixed-rate and variable-rate | | 5,973 | | 306 | | | ― | | ― | | | ― | | ― |
| At December 31, 2013 | | | | | | | | | | | | | | |
| California Utilities fixed-rate | $ | 5,464 | $ | 531 | | $ | 4,051 | $ | 407 | | $ | 1,413 | $ | 124 |
| California Utilities variable-rate | | 335 | | 15 | | | 335 | | 15 | | | ― | | ― |
| All other, fixed-rate and variable-rate | | 6,211 | | 308 | | | ― | | ― | | | ― | | ― |
| (1) | Excluding commercial paper classified as long-term debt at Sempra Energy, capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium. |
| (2) | After the effects of interest rate swaps. |
We provide further information about interest rate swap transactions in Note 9 of the Notes to Consolidated Financial Statements.
We also are subject to the effect of interest rate fluctuations on the assets of our pension plans, other postretirement benefit plans, and SDG&E’s nuclear decommissioning trusts. However, we expect the effects of these fluctuations, as they relate to the California Utilities, to be passed on to customers.
Credit Risk
Credit risk is the risk of loss that would be incurred as a result of nonperformance of our counterparties’ contractual obligations. We monitor credit risk through a credit-approval process and the assignment and monitoring of credit limits. We establish these credit limits based on risk and return considerations under terms customarily available in the industry.
As with market risk, we have policies governing the management of credit risk that are administered by the respective credit departments for each of the California Utilities and, on a combined basis, for all non-CPUC regulated affiliates and overseen by their separate risk management committees.
This oversight includes calculating current and potential credit risk on a daily basis and monitoring actual balances in comparison to approved limits. We avoid concentration of counterparties whenever possible, and we believe our credit policies significantly reduce overall credit risk. These policies include an evaluation of:
| § | prospective counterparties’ financial condition (including credit ratings) |
| § | collateral requirements |
| § | the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty |
We believe that we have provided adequate reserves for counterparty nonperformance.
When development projects at Sempra International and Sempra U.S. Gas & Power become operational, they rely significantly on the ability of their suppliers to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. Also, the factors that we consider in evaluating a development project include negotiating customer and supplier agreements and, therefore, we rely on these agreements for future performance. We also may base our decision to go forward on development projects on these agreements.
As noted above under “Interest Rate Risk,” we periodically enter into interest rate swap agreements to moderate exposure to interest rate changes and to lower the overall cost of borrowing. We would be exposed to interest rate fluctuations on the underlying debt should a counterparty to the swap fail to perform.
Foreign Currency Rate Risk
We have investments in entities whose functional currency is not the U.S. dollar, exposing us to foreign exchange movements, primarily in currencies in Chile and Peru.
We discuss our foreign currency exposure at our Mexican subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Income Taxes – Foreign Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity.”
Our primary objective in reducing foreign currency risk is to preserve the economic value of our foreign investments and to reduce earnings volatility that would otherwise occur due to exchange rate fluctuations. We may offset material cross-currency transactions and net income exposure through various means, including financial instruments and short-term investments. Because we do not hedge our net investment in foreign countries, we are susceptible to volatility in other comprehensive income caused by exchange rate fluctuations.
The hypothetical effects for every one percent appreciation in the U.S. dollar from year-end 2014 levels against the currencies of Mexico, Chile and Peru in which we have operations and investments are as follows:
| (Dollars in millions) | | Hypothetical effects |
| | Translation of 2014 earnings to U.S. dollars | $ | (2) |
| | Transactional exposure | | (6) |
| | Translation of net assets of foreign subsidiaries and investment in foreign entities | | (20) |
Foreign Inflation Risk
Monetary assets and liabilities at our Mexican subsidiaries that are denominated in U.S. dollars may fluctuate significantly throughout the year. Based on a net monetary liability position of $243 million at December 31, 2014, the hypothetical effect on Sempra Energy for every one percent increase in the Mexican inflation rate is approximately $0.7 million of additional income tax expense at our Mexican subsidiaries.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, AND KEY NONCASH PERFORMANCE INDICATORS
Management views 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 describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements. We discuss choices among alternative accounting policies that are material to our financial statements and information concerning significant estimates with the audit committee of the Sempra Energy board of directors.
| CRITICAL ACCOUNTING POLICIES AND ESTIMATES | | |
SEMPRA ENERGY, SDG&E AND SOCALGAS | | |
CONTINGENCIES | | |
| Assumptions & Approach Used | | We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and: § information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events, and § the amount of the loss can be reasonably estimated. We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events. | | |
Effect if Different Assumptions Used | | Details of our issues in this area are discussed in Note 15 of the Notes to Consolidated Financial Statements. |
REGULATORY ACCOUNTING | | |
| Assumptions & Approach Used | | As regulated entities, the California Utilities’ rates, as set and monitored by regulators, are designed to recover the cost of providing service and provide the opportunity to earn a competitive return on their investments. The California Utilities record regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover that asset from customers in future rates. Similarly, regulatory liabilities are recorded for amounts recovered in rates in advance or in excess of costs incurred. The California Utilities assess probabilities of future rate recovery associated with regulatory account balances at the end of each reporting period and whenever new and/or unusual events occur, such as: § changes in the regulatory and political environment or the utility’s competitive position § issuance of a regulatory commission order § passage of new legislation To the extent that circumstances associated with regulatory balances change, the regulatory balances are adjusted accordingly. | | |
Effect if Different Assumptions Used | | Adverse legislative or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could materially adversely impact our financial statements. Details of the California Utilities’ regulatory assets and liabilities and additional factors that management considers when assessing probabilities associated with regulatory balances are discussed in Notes 1, 13, 14 and 15 of the Notes to Consolidated Financial Statements. |
SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED) |
INCOME TAXES |
| Assumptions & Approach Used | | Our income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. When we evaluate the anticipated resolution of income tax issues, we consider § past resolutions of the same or similar issue § the status of any income tax examination in progress § positions taken by taxing authorities with other taxpayers with similar issues The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and our expectation of future taxable income, based on our strategic planning. |
Effect if Different Assumptions Used | | Actual income taxes could vary from estimated amounts because of: § future impacts of various items, including changes in tax laws, regulations, interpretations and rulings § our financial condition in future periods § the resolution of various income tax issues between us and taxing authorities We discuss details of our issues in this area in Note 6 of the Notes to Consolidated Financial Statements. |
| Assumptions & Approach Used | | For an uncertain position to qualify for benefit recognition, the position must have at least a “more likely than not” chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. If we do not have a more likely than not position with respect to a tax position, then we do not recognize any of the potential tax benefit associated with the position. A tax position that meets the “more likely than not” recognition is measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon the effective resolution of the tax position. |
Effect if Different Assumptions Used | | Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial position and cash flows. We discuss additional information related to accounting for uncertainty in income taxes in Note 6 of the Notes to Consolidated Financial Statements. |
SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED) |
DERIVATIVES |
| Assumptions & Approach Used | | We value derivative instruments at fair value on the balance sheet. Depending on the purpose for the contract and the applicability of hedge accounting, the impact of instruments may be offset in earnings, on the balance sheet, or in other comprehensive income. We also use normal purchase or sale accounting for certain contracts. As discussed elsewhere in this report, whenever possible, we use exchange quotations or other third-party pricing to estimate fair values; if no such data is available, we use internally developed models and other techniques. The assumed collectability of derivative assets and receivables considers § events specific to a given counterparty § the tenor of the transaction § the credit-worthiness of the counterparty |
Effect if Different Assumptions Used | | The application of hedge accounting to certain derivatives and the normal purchase or sale accounting election is made on a contract-by-contract basis. Using hedge accounting or the normal purchase or sale election in a different manner could materially impact Sempra Energy’s results of operations. However, such alternatives would not have a significant impact on the California Utilities’ results of operations because of regulatory accounting principles. We provide details of our financial instruments in Note 9 of the Notes to Consolidated Financial Statements. |
DEFINED BENEFIT PLANS |
| Assumptions & Approach Used | | To measure our pension and other postretirement obligations, costs and liabilities, we rely on several assumptions. We consider current market conditions, including interest rates, in making these assumptions. We annually review these assumptions prior to the beginning of each year and update when appropriate. The critical assumptions used to develop the required estimates include the following key factors: § discount rates § expected return on plan assets § health care cost trend rates § mortality rates § rate of compensation increases § termination and retirement rates § utilization of postretirement welfare benefits § payout elections (lump sum or annuity) § lump sum interest rates | |
SEMPRA ENERGY, SDG&E AND SOCALGAS (CONTINUED) |
DEFINED BENEFIT PLANS (CONTINUED) |
Effect if Different Assumptions Used | | The actuarial assumptions we use may differ materially from actual results due to: § return on plan assets § changing market and economic conditions § higher or lower withdrawal rates § longer or shorter participant life spans § more or fewer lump sum versus annuity payout elections made by plan participants § retirement rates These differences, other than those related to the California Utilities’ plans, where rate recovery offsets any effects of the assumptions on earnings, may result in a significant impact to the amount of pension and postretirement benefit expense we record. For the remaining plans, the approximate annual effect on earnings of a 100 basis point increase or decrease in the assumed discount rate would be less than $3 million and the effect of a 100 basis point increase or decrease in the assumed rate of return on plan assets would be less than $2 million. We provide additional information, including the impact of increases and decreases in the health care cost trend rate, in Note 7 of the Notes to Consolidated Financial Statements. |
SEMPRA ENERGY AND SDG&E |
ASSET RETIREMENT OBLIGATIONS |
| Assumptions & Approach Used | | SDG&E’s legal asset retirement obligations (AROs) related to the decommissioning of SONGS are recorded at fair value based on a site specific study performed no less than every three years. The fair value of the obligations includes § estimated decommissioning costs, including labor, equipment, material and other disposal costs § inflation adjustment applied to estimated cash flows § discount rate based on a credit-adjusted risk-free rate § expected initiation and duration of decommissioning activities |
Effect if Different Assumptions Used | | Changes in the estimated decommissioning costs, or in the assumptions and judgments made by management underlying these estimates, could cause revisions to the estimated total cost associated with retiring the assets. SDG&E’s nuclear decommissioning expenses are subject to rate recovery and, therefore, rate-making accounting treatment is applied to SDG&E’s nuclear decommissioning activities. SDG&E recognizes a regulatory asset, or liability, to the extent that its SONGS ARO exceeds, or is less than, the amount collected from customers and the amount earned in SDG&E’s Nuclear Decommissioning Trusts. We provide additional detail in Notes 13 and 15 of the Notes to the Consolidated Financial Statements. |
SEMPRA ENERGY |
IMPAIRMENT TESTING OF LONG-LIVED ASSETS |
| Assumptions & Approach Used | | Whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable, we consider if the estimated future undiscounted cash flows are less than the carrying amount of the assets. If so, we estimate the fair value of these assets to determine the extent to which cost exceeds fair value. For these estimates, we may consider data from multiple valuation methods, including data from market participants. We exercise judgment to estimate the future cash flows and the useful lives of long-lived assets and to determine our intent to use the assets. Our intent to use or dispose of assets is subject to re-evaluation and can change over time. |
Effect if Different Assumptions Used | | If an impairment test is required, the fair value of long-lived assets can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. We discuss impairment of long-lived assets in Note 1 of the Notes to Consolidated Financial Statements. |
IMPAIRMENT TESTING OF GOODWILL |
| Assumptions & Approach Used | | On an annual basis or whenever events or changes in circumstances necessitate an evaluation, we consider whether goodwill may be impaired. For our annual goodwill impairment testing, we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and compare that to the carrying value. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include § consideration of market transactions § future cash flows § the appropriate risk-adjusted discount rate § country risk § entity risk |
Effect if Different Assumptions Used | | When we choose to make a qualitative assessment as discussed above, the two-step, quantitative goodwill impairment test is not required if we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit is less than its carrying amount or when we choose to proceed directly to the two-step, quantitative goodwill impairment test, the test requires us to first determine if the carrying value of a reporting unit exceeds its fair value and if so, to measure the amount of goodwill impairment, if any. When determining if goodwill is impaired, the fair value of the reporting unit and goodwill can vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions. As a result, recognizing a goodwill impairment may or may not be required. Sempra Energy has $931 million of goodwill on its Consolidated Balance Sheet at December 31, 2014, of which $834 million is attributable to our operations in South America. Based on our qualitative assessment, we determined that it is more likely than not that the estimated fair values of the reporting units to which this goodwill was allocated substantially exceeded their carrying values as of October 1, 2014, our most recent goodwill impairment testing date. We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements. |
SEMPRA ENERGY |
CARRYING VALUE OF EQUITY METHOD INVESTMENTS |
| Assumptions & Approach Used | | We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. We consider whether the fair value of each equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. To help evaluate whether a decline in fair value below cost has occurred and if the decline is other than temporary, we may develop fair value estimates for the investment. Our fair value estimates are developed from the perspective of a knowledgeable market participant. In the absence of observable transactions in the marketplace for similar investments, we consider an income-based approach such as discounted cash flow analysis or, with less weighting, the replacement cost of the underlying net assets. A discounted cash flow analysis may be based directly on anticipated future distributions from the investment, or may be performed based on free cash flows generated within the entity and adjusted for our ownership share total. When calculating estimates of fair or realizable values, we also consider whether we intend to hold or sell the investment. For certain held investments, critical assumptions may include § equity sale offer price for the investment § transportation rates for natural gas § the appropriate risk-adjusted discount rate § the availability and costs of natural gas and liquefied natural gas § competing fuels (primarily propane) and electricity § estimated future power generation and associated production tax credits § renewable power price expectations For investments that we hold for sale, we consider comparable sales values or indicative offers, executed sales transactions or indications of value determined by cash and affiliate receivables within the entity when determining our estimates of fair value. |
Effect if Different Assumptions Used | | The risk assumptions applied by other market participants to value the investments could vary significantly or the appropriate approaches could be weighted differently. These differences could impact whether or not the fair value of the investment is less than its cost, and if so, whether that condition is other than temporary. This could result in an impairment charge or a different amount of impairment charge, and, in cases where an impairment charge has been recorded, additional loss or gain upon sale. We provide additional details in Notes 4 and 10 of the Notes to Consolidated Financial Statements. |
KEY NONCASH PERFORMANCE INDICATORS
A discussion of key noncash performance indicators related to each segment follows:
California Utilities
Key noncash performance indicators include number of customers, and natural gas volumes and electricity sold. Additional noncash performance indicators include goals related to safety, customer service, customer reputation, environmental considerations, on-time and on-budget completion of major projects and initiatives, and in the case of SDG&E, electric reliability. We discuss natural gas volumes and electricity sold in “Results of Operations – Changes in Revenues, Costs and Earnings” above.
Sempra South American Utilities
Key noncash performance indicators for our South American distribution operations are customer count and consumption. We discuss these above in “Our Business.” Additional noncash performance indicators include goals related to safety, environmental considerations, electric reliability, and regulatory compliance.
Sempra Mexico
Key noncash performance indicators for Sempra Mexico include natural gas sales volume, facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include goals related to safety, environmental considerations and regulatory performance. We discuss these above in “Our Business.”
Sempra Natural Gas
Key noncash performance indicators at Sempra Natural Gas include natural gas sales volume, facility availability, capacity utilization and, for its distribution operations, customer count and consumption. Additional noncash performance indicators include goals related to safety, environmental considerations and regulatory compliance. We discuss these above in “Our Business.”
Electric Generation Facilities (Sempra Mexico, Sempra Renewables and Sempra Natural Gas)
Key noncash performance indicators include plant availability and capacity factors and sales volume at our renewable energy facilities and natural gas-fired generating plants. For competitive reasons, we do not disclose plant availability factors. We discuss the other indicators above in “Our Business” and “Factors Influencing Future Performance.” Additional noncash performance indicators include goals related to safety, environmental considerations, and compliance with reliability standards.
LNG Facilities (Sempra Mexico and Sempra Natural Gas)
Key noncash performance indicators include plant availability and capacity utilization. We discuss these above in “Our Business” and “Factors Influencing Future Performance.” Additional noncash performance indicators include goals related to safety, environmental considerations, regulatory compliance, and on-time and on-budget completion of development projects.
We discuss the relevant pronouncements that have recently become effective and have had or may have a significant effect on our financial statements in Note 2 of the Notes to Consolidated Financial Statements.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
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,” “confident,” “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, U.S. Environmental Protection Agency, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate; |
| § | the timing and success of business development efforts and construction, maintenance and capital projects, including risks in obtaining, maintaining or extending permits, licenses, certificates and other authorizations on a timely basis and risks in obtaining adequate and competitive financing for such projects; |
| § | energy markets, including the timing and extent of changes and volatility in commodity prices, and the impact of any protracted reduction in oil prices from historical averages; |
| § | the impact on the value of our natural gas storage assets from low natural gas prices, low volatility of natural gas prices and the inability to procure favorable long-term contracts for natural gas storage services; |
| § | delays in the timing of costs incurred and the timing of the regulatory agency authorization to recover such costs in rates from customers; |
| § | capital markets conditions, including the availability of credit and the liquidity of our investments; |
| § | inflation, interest and currency exchange rates; |
| § | the impact of benchmark interest rates, generally Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital; |
| § | the availability of electric power, natural gas and liquefied natural gas, and natural gas pipeline and storage capacity, 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); |
| § | cybersecurity threats to the energy grid, natural gas storage and pipeline infrastructure, the information and systems used to operate our businesses and the confidentiality of our proprietary information and the personal information of our customers, terrorist attacks that threaten system operations and critical infrastructure, and wars; |
| § | the ability to win competitively bid infrastructure projects against a number of strong competitors willing to aggressively bid for these projects; |
| § | weather conditions, conservation efforts, natural disasters, catastrophic accidents, and other events that may disrupt our operations, damage our facilities and systems, and subject us to third-party liability for property damage or personal injuries; |
| § | 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; |
| § | 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; |
| § | 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 due to insufficient market interest, unattractive pricing or other factors; |
| § | 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 herein and in our Annual Report on Form 10-K and other reports that we file with the Securities and Exchange Commission.
SEMPRA ENERGY COMMON STOCK
Our common stock is traded on the New York Stock Exchange. At February 20, 2015, there were approximately 31,765 record holders of our common stock.
The following table shows Sempra Energy quarterly common stock data:
| QUARTERLY COMMON STOCK DATA |
| | | | | | | | | |
| | First | Second | Third | Fourth |
| | quarter | quarter | quarter | quarter |
| 2014 | | | | | | | | |
| Market price | | | | | | | | |
| High | $ | 97.48 | $ | 105.25 | $ | 107.81 | $ | 116.30 |
| Low | $ | 86.73 | $ | 95.15 | $ | 96.13 | $ | 98.34 |
| | | | | | | | | |
| 2013 | | | | | | | | |
| Market price | | | | | | | | |
| High | $ | 80.21 | $ | 84.85 | $ | 89.46 | $ | 93.00 |
| Low | $ | 70.61 | $ | 78.11 | $ | 78.67 | $ | 84.55 |
We declared dividends of $0.66 per share and $0.63 per share in each quarter of 2014 and 2013, respectively. On February 20, 2015, our board of directors approved an increase to our quarterly common stock dividend to $0.70 per share ($2.80 annually), an increase of $0.04 per share ($0.16 annually) from $0.66 per share ($2.64 annually) authorized in February 2014.
SOCALGAS AND SDG&E COMMON STOCK
Pacific Enterprises, a wholly owned subsidiary of Sempra Energy, owns all of SoCalGas’ outstanding common stock. Enova Corporation, a wholly owned subsidiary of Sempra Energy, owns all of SDG&E’s issued and outstanding common stock.
Information concerning dividend declarations for SoCalGas and SDG&E is included in their Statements of Changes in Shareholders’ Equity and Statements of Changes in Equity, respectively, set forth in the Consolidated Financial Statements.
The payment and the amount of future dividends for Sempra Energy, SDG&E, and SoCalGas are within the discretion of their boards of directors. The CPUC’s regulation of the California Utilities’ capital structures limits the amounts that the California Utilities can pay us in the form of loans and dividends. We discuss these matters in Note 1 of the Notes to the Consolidated Financial Statements under “Restricted Net Assets” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” in the “Overview – Sempra Energy Consolidated,” “Overview – California Utilities” and “Dividends” sections.
PERFORMANCE GRAPH -- COMPARATIVE TOTAL SHAREHOLDER RETURNS
The following graph (Figure 2) compares the percentage change in the cumulative total shareholder return on Sempra Energy common stock for the five-year period ending December 31, 2014, with the performance over the same period of the Standard & Poor’s (S&P) 500 Index and the Standard & Poor’s 500 Utilities Index.
These returns were calculated assuming an initial investment of $100 in our common stock, the S&P 500 Index and the S&P 500 Utilities Index on December 31, 2009, and the reinvestment of all dividends.
![[i002.gif]](https://capedge.com/proxy/10-K/0000086521-15-000011/i002.gif)
Figure 2: Comparison of Cumulative Five-Year Total Return
The following tables present selected financial data of Sempra Energy, SDG&E and SoCalGas for the five years ended December 31, 2014. The data is derived from the audited consolidated financial statements of each company. You should read this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes contained in this Annual Report.
| FIVE-YEAR SUMMARY OF SELECTED FINANCIAL DATA FOR SEMPRA ENERGY |
| (In millions, except per share amounts) |
| | | At December 31 or for the years then ended |
| | | 2014 | 2013 | 2012 | 2011 | 2010 |
| Sempra Energy Consolidated: | | | | | | | | | | | | | | | |
| Revenues | | | | | | | | | | | | | | | |
| Utilities: | | | | | | | | | | | | | | | |
| Electric | $ | 5,209 | | $ | 4,911 | | $ | 4,568 | | $ | 3,833 | | $ | 2,528 | |
| Natural gas | | 4,549 | | | 4,398 | | | 3,873 | | | 4,489 | | | 4,491 | |
| Energy-related businesses | | 1,277 | | | 1,248 | | | 1,206 | | | 1,714 | | | 1,984 | |
| Total revenues | $ | 11,035 | | $ | 10,557 | | $ | 9,647 | | $ | 10,036 | | $ | 9,003 | |
| | | | | | | | | | | | | | | | |
| Income from continuing operations | $ | 1,262 | | $ | 1,088 | | $ | 920 | | $ | 1,381 | | $ | 703 | |
| (Earnings) losses from continuing operations | | | | | | | | | | | | | | | |
| attributable to noncontrolling interests | | (100) | | | (79) | | | (55) | | | (42) | | | 16 | |
| Call premium on preferred stock of subsidiary | | ― | | | (3) | | | ― | | | ― | | | ― | |
| Preferred dividends of subsidiaries | | (1) | | | (5) | | | (6) | | | (8) | | | (10) | |
| Earnings/Income from continuing operations | | | | | | | | | | | | | | | |
| attributable to common shares | $ | 1,161 | | $ | 1,001 | | $ | 859 | | $ | 1,331 | | $ | 709 | |
| | | | | | | | | | | | | | | | |
| Attributable to common shares: | | | | | | | | | | | | | | | |
| Earnings/Income from continuing operations | | | | | | | | | | | | | | | |
| Basic | $ | 4.72 | | $ | 4.10 | | $ | 3.56 | | $ | 5.55 | | $ | 2.90 | |
| Diluted | $ | 4.63 | | $ | 4.01 | | $ | 3.48 | | $ | 5.51 | | $ | 2.86 | |
| | | | | | | | | | | | | | | | |
| Dividends declared per common share | $ | 2.64 | | $ | 2.52 | | $ | 2.40 | | $ | 1.92 | | $ | 1.56 | |
| Return on common equity | | 10.4 | % | | 9.4 | % | | 8.6 | % | | 14.2 | % | | 7.9 | % |
| Effective income tax rate | | 20 | % | | 26 | % | | 6 | % | | 23 | % | | 17 | % |
| Price range of common shares: | | | | | | | | | | | | | | | |
| High | $ | 116.30 | | $ | 93.00 | | $ | 72.87 | | $ | 55.97 | | $ | 56.61 | |
| Low | $ | 86.73 | | $ | 70.61 | | $ | 54.70 | | $ | 44.78 | | $ | 43.91 | |
| | | | | | | | | | | | | | | | |
| Weighted average rate base: | | | | | | | | | | | | | | | |
| SDG&E | $ | 7,253 | | $ | 7,244 | | $ | 6,295 | | $ | 5,071 | | $ | 4,697 | |
| SoCalGas | $ | 3,879 | | $ | 3,499 | | $ | 3,178 | | $ | 2,948 | | $ | 2,860 | |
| | | | | | | | | | | | | | | | |
| AT DECEMBER 31 | | | | | | | | | | | | | | | |
| Current assets | $ | 4,184 | | $ | 3,997 | | $ | 3,695 | | $ | 2,332 | | $ | 3,363 | |
| Total assets | $ | 39,732 | | $ | 37,244 | | $ | 36,499 | | $ | 33,249 | | $ | 30,231 | |
| Current liabilities | $ | 5,069 | | $ | 4,369 | | $ | 4,258 | | $ | 4,152 | | $ | 3,786 | |
| Long-term debt (excludes current portion) | $ | 12,167 | | $ | 11,253 | | $ | 11,621 | | $ | 10,078 | | $ | 8,980 | |
| Short-term debt(1) | $ | 2,202 | | $ | 1,692 | | $ | 1,271 | | $ | 785 | | $ | 507 | |
| Contingently redeemable preferred stock | | | | | | | | | | | | | | | |
| of subsidiary(2) | $ | ― | | $ | ― | | $ | 79 | | $ | 79 | | $ | 79 | |
| Sempra Energy shareholders’ equity | $ | 11,326 | | $ | 11,008 | | $ | 10,282 | | $ | 9,775 | | $ | 8,990 | |
| Common shares outstanding | | 246.3 | | | 244.5 | | | 242.4 | | | 239.9 | | | 240.4 | |
| Book value per share | $ | 45.98 | | $ | 45.03 | | $ | 42.43 | | $ | 40.74 | | $ | 37.39 | |
| (1) | Includes long-term debt due within one year. | | | | | | | | | | | | | | | |
| (2) | SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013, as we discuss in Note 11 of the Notes to Consolidated Financial Statements. |
On October 1, 2014, Cameron LNG Holdings, a joint venture between Sempra Natural Gas and its partners in the Cameron LNG liquefaction project, became effective. Sempra Natural Gas is accounting for its investment in the joint venture under the equity method. We discuss Cameron LNG Holdings further in Notes 3 and 4 of the Notes to Consolidated Financial Statements.
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. We discuss the offerings and IEnova further in Note 1 of the Notes to Consolidated Financial Statements.
In June 2013, we recorded a $200 million pretax loss from plant closure related to SDG&E’s investment in SONGS. We discuss this loss further in Note 13 of the Notes to Consolidated Financial Statements.
In 2012, we recorded $239 million in after-tax impairment charges related to our investment in the Rockies Express joint venture. We discuss Rockies Express further in Notes 4 and 10 of the Notes to Consolidated Financial Statements.
We discuss the impact of natural gas prices on revenues in 2014, 2013 and 2012 and the changes in our effective income tax rate in 2014 and 2013 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Changes in Revenues, Costs and Earnings.”
On April 6, 2011, we increased our interests in two South American utilities, which are now consolidated. Prior to the acquisition, we accounted for our investments in these entities as equity method investments. In conjunction with the transaction, we recorded a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments.
On April 1, 2008, we sold our commodities-marketing businesses into a joint venture, and began accounting for these businesses under the equity method. In 2010 and early 2011, we and RBS sold substantially all of the businesses and assets of the joint venture. In 2010, we recorded a $139 million after-tax impairment charge related to our remaining investment in the joint venture.
We discuss litigation and other contingencies in Note 15 of the Notes to Consolidated Financial Statements.
| FIVE-YEAR SUMMARIES OF SELECTED FINANCIAL DATA FOR SDG&E AND SOCALGAS |
| (Dollars in millions) |
| | | At December 31 or for the years then ended |
| | | 2014 | 2013 | 2012 | 2011 | 2010 |
| SDG&E: | | | | | | | | | | |
| Statement of Operations Data: | | | | | | | | | | |
| Operating revenues | $ | 4,329 | $ | 4,066 | $ | 3,694 | $ | 3,373 | $ | 3,049 |
| Operating income | | 959 | | 782 | | 809 | | 755 | | 657 |
| Dividends on preferred stock | | ― | | 4 | | 5 | | 5 | | 5 |
| Earnings attributable to common shares | | 507 | | 404 | | 484 | | 431 | | 369 |
| | | | | | | | | | | |
| Balance Sheet Data: | | | | | | | | | | |
| Total assets | $ | 16,296 | $ | 15,377 | $ | 14,744 | $ | 13,555 | $ | 12,077 |
| Long-term debt (excludes current portion) | | 4,319 | | 4,525 | | 4,292 | | 4,058 | | 3,479 |
| Short-term debt(1) | | 611 | | 88 | | 16 | | 19 | | 19 |
| Contingently redeemable preferred stock(2) | | ― | | ― | | 79 | | 79 | | 79 |
| SDG&E shareholder's equity | | 4,932 | | 4,628 | | 4,222 | | 3,739 | | 3,108 |
| SoCalGas: | | | | | | | | | | |
| Statement of Operations Data: | | | | | | | | | | |
| Operating revenues | $ | 3,855 | $ | 3,736 | $ | 3,282 | $ | 3,816 | $ | 3,822 |
| Operating income | | 521 | | 539 | | 420 | | 486 | | 516 |
| Dividends on preferred stock | | 1 | | 1 | | 1 | | 1 | | 1 |
| Earnings attributable to common shares | | 332 | | 364 | | 289 | | 287 | | 286 |
| | | | | | | | | | | |
| Balance Sheet Data: | | | | | | | | | | |
| Total assets | $ | 10,461 | $ | 9,147 | $ | 9,071 | $ | 8,475 | $ | 7,986 |
| Long-term debt (excludes current portion) | | 1,906 | | 1,159 | | 1,409 | | 1,064 | | 1,320 |
| Short-term debt(1) | | 50 | | 294 | | 4 | | 257 | | 262 |
| SoCalGas shareholders’ equity | | 2,781 | | 2,549 | | 2,235 | | 2,193 | | 1,955 |
| (1) | Includes long-term debt due within one year. |
| (2) | SDG&E redeemed all series of its outstanding shares of contingently redeemable stock in 2013, as we discuss in Note 11 of the Notes to Consolidated Financial Statements. |
In June 2013, SDG&E recorded a $200 million pretax loss from plant closure related to its investment in SONGS.
We discuss the impact of natural gas prices on revenues in 2014, 2013 and 2012 in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Changes in Revenues, Costs and Earnings.” We do not provide per-share data for SDG&E and SoCalGas because their common stock is indirectly wholly owned by Sempra Energy.
We discuss litigation and other contingencies in Note 15 of the Notes to Consolidated Financial Statements.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
SEMPRA ENERGY, SDG&E, SOCALGAS
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 December 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.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
SEMPRA ENERGY, SDG&E, SOCALGAS
The respective management of each company is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of the management of each company, including each company’s principal executive officer and principal financial officer, the effectiveness of each company’s internal control over financial reporting was evaluated based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluations, each company concluded that its internal control over financial reporting was effective as of December 31, 2014. Deloitte & Touche LLP audited the effectiveness of each company’s internal control over financial reporting as of December 31, 2014, as stated in their reports, which are included in this Annual Report.
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.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Sempra Energy:
We have audited the internal control over financial reporting of Sempra Energy and subsidiaries (the “Company”) as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
To the Board of Directors and Shareholders of Sempra Energy:
We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sempra Energy and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
SAN DIEGO GAS & ELECTRIC COMPANY
To the Board of Directors and Shareholder of San Diego Gas & Electric Company:
We have audited the internal control over financial reporting of San Diego Gas & Electric Company (the “Company”) as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
To the Board of Directors and Shareholder of San Diego Gas & Electric Company:
We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of San Diego Gas & Electric Company as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
SOUTHERN CALIFORNIA GAS COMPANY
To the Board of Directors and Shareholders of Southern California Gas Company:
We have audited the internal control over financial reporting of Southern California Gas Company and subsidiaries (the “Company”) as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
To the Board of Directors and Shareholders of Southern California Gas Company:
We have audited the accompanying consolidated balance sheets of Southern California Gas Company and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southern California Gas Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 26, 2015
| SEMPRA ENERGY |
| CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions, except per share amounts) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| | | |
| REVENUES | | | | | | |
| Utilities | $ | 9,758 | $ | 9,309 | $ | 8,441 |
| Energy-related businesses | | 1,277 | | 1,248 | | 1,206 |
| Total revenues | | 11,035 | | 10,557 | | 9,647 |
| EXPENSES AND OTHER INCOME | | | | | | |
| Utilities: | | | | | | |
| Cost of natural gas | | (1,758) | | (1,646) | | (1,290) |
| Cost of electric fuel and purchased power | | (2,281) | | (1,932) | | (1,760) |
| Energy-related businesses: | | | | | | |
| Cost of natural gas, electric fuel and purchased power | | (552) | | (435) | | (481) |
| Other cost of sales | | (163) | | (178) | | (159) |
| Operation and maintenance | | (2,935) | | (2,995) | | (2,956) |
| Depreciation and amortization | | (1,156) | | (1,113) | | (1,090) |
| Franchise fees and other taxes | | (408) | | (374) | | (359) |
| Plant closure loss | | (6) | | (200) | | ― |
| Gain on sale of equity interests and assets | | 62 | | 114 | | 7 |
| Equity earnings (losses), before income tax | | 81 | | 31 | | (319) |
| Other income, net | | 137 | | 140 | | 172 |
| Interest income | | 22 | | 20 | | 24 |
| Interest expense | | (554) | | (559) | | (493) |
| Income before income taxes and equity earnings | | | | | | |
| of certain unconsolidated subsidiaries | | 1,524 | | 1,430 | | 943 |
| Income tax expense | | (300) | | (366) | | (59) |
| Equity earnings, net of income tax | | 38 | | 24 | | 36 |
| Net income | | 1,262 | | 1,088 | | 920 |
| Earnings attributable to noncontrolling interests | | (100) | | (79) | | (55) |
| Call premium on preferred stock of subsidiary | | ― | | (3) | | ― |
| Preferred dividends of subsidiaries | | (1) | | (5) | | (6) |
| Earnings | $ | 1,161 | $ | 1,001 | $ | 859 |
| | | | | | | | |
| | | | | | | | |
| Basic earnings per common share | $ | 4.72 | $ | 4.10 | $ | 3.56 |
| Weighted-average number of shares outstanding, basic (thousands) | | 245,891 | | 243,863 | | 241,347 |
| | | | | | | | |
| Diluted earnings per common share | $ | 4.63 | $ | 4.01 | $ | 3.48 |
| Weighted-average number of shares outstanding, diluted (thousands) | | 250,655 | | 249,332 | | 246,693 |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| (Dollars in millions) |
| | | Years ended December 31, 2014, 2013 and 2012 |
| | | Sempra Energy shareholders' equity | | | | |
| | | Pretax | Income tax | Net-of-tax | Noncontrolling | |
| | | amount | (expense) benefit | amount | interests (after-tax) | Total |
| 2014: | | | | | | | | | | |
| Net income | $ | 1,462 | $ | (300) | $ | 1,162 | $ | 100 | $ | 1,262 |
| Other comprehensive loss: | | | | | | | | | | |
| Foreign currency translation adjustments | | (193) | | ― | | (193) | | (20) | | (213) |
| Pension and other postretirement benefits | | (20) | | 8 | | (12) | | ― | | (12) |
| Financial instruments | | (106) | | 42 | | (64) | | (1) | | (65) |
| Total other comprehensive loss | | (319) | | 50 | | (269) | | (21) | | (290) |
| Comprehensive income | | 1,143 | | (250) | | 893 | | 79 | | 972 |
| Preferred dividends of subsidiary | | (1) | | ― | | (1) | | ― | | (1) |
| Comprehensive income, after | | | | | | | | | | |
| preferred dividends of subsidiary | $ | 1,142 | $ | (250) | $ | 892 | $ | 79 | $ | 971 |
| 2013: | | | | | | | | | | |
| Net income | $ | 1,375 | $ | (366) | $ | 1,009 | $ | 79 | $ | 1,088 |
| Other comprehensive income (loss): | | | | | | | | | | |
| Foreign currency translation adjustments | | 111 | | ― | | 111 | | (27) | | 84 |
| Pension and other postretirement benefits | | 47 | | (19) | | 28 | | ― | | 28 |
| Financial instruments | | 13 | | (4) | | 9 | | 19 | | 28 |
| Total other comprehensive income (loss) | | 171 | | (23) | | 148 | | (8) | | 140 |
| Comprehensive income | | 1,546 | | (389) | | 1,157 | | 71 | | 1,228 |
| Preferred dividends of subsidiaries | | (5) | | ― | | (5) | | ― | | (5) |
| Comprehensive income, after | | | | | | | | | | |
| preferred dividends of subsidiaries | $ | 1,541 | $ | (389) | $ | 1,152 | $ | 71 | $ | 1,223 |
| 2012: | | | | | | | | | | |
| Net income | $ | 924 | $ | (59) | $ | 865 | $ | 55 | $ | 920 |
| Other comprehensive income (loss): | | | | | | | | | | |
| Foreign currency translation adjustments | | 119 | | ― | | 119 | | 15 | | 134 |
| Pension and other postretirement benefits | | (4) | | 2 | | (2) | | ― | | (2) |
| Financial instruments | | (6) | | 2 | | (4) | | (11) | | (15) |
| Total other comprehensive income | | 109 | | 4 | | 113 | | 4 | | 117 |
| Comprehensive income | | 1,033 | | (55) | | 978 | | 59 | | 1,037 |
| Preferred dividends of subsidiaries | | (6) | | ― | | (6) | | ― | | (6) |
| Comprehensive income, after | | | | | | | | | | |
| preferred dividends of subsidiaries | $ | 1,027 | $ | (55) | $ | 972 | $ | 59 | $ | 1,031 |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED BALANCE SHEETS |
| (Dollars in millions) |
| | | December 31, | December 31, |
| | | 2014 | 2013 |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | $ | 570 | $ | 904 |
| Restricted cash | | 11 | | 24 |
| Trade accounts receivable, net | | 1,242 | | 1,308 |
| Other accounts and notes receivable, net | | 152 | | 214 |
| Due from unconsolidated affiliates | | 38 | | 4 |
| Income taxes receivable | | 45 | | 85 |
| Deferred income taxes | | 305 | | 301 |
| Inventories | | 396 | | 287 |
| Regulatory balancing accounts – undercollected | | 746 | | 556 |
| Fixed-price contracts and other derivatives | | 93 | | 106 |
| Asset held for sale, power plant | | 293 | | ― |
| Other | | 293 | | 208 |
| Total current assets | | 4,184 | | 3,997 |
| | | | | |
| Investments and other assets: | | | | |
| Restricted cash | | 29 | | 25 |
| Due from unconsolidated affiliates | | 188 | | 14 |
| Regulatory assets | | 3,031 | | 2,548 |
| Nuclear decommissioning trusts | | 1,131 | | 1,034 |
| Investments | | 2,848 | | 1,575 |
| Goodwill | | 931 | | 1,024 |
| Other intangible assets | | 415 | | 426 |
| Dedicated assets in support of certain benefit plans | | 512 | | 506 |
| Sundry | | 561 | | 635 |
| Total investments and other assets | | 9,646 | | 7,787 |
| | | | | |
| Property, plant and equipment: | | | | |
| Property, plant and equipment | | 35,407 | | 34,407 |
| Less accumulated depreciation and amortization | | (9,505) | | (8,947) |
| Property, plant and equipment, net ($410 and $438 at December 31, 2014 and | | | | |
| 2013, respectively, related to VIE) | | 25,902 | | 25,460 |
| Total assets | $ | 39,732 | $ | 37,244 |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED BALANCE SHEETS (CONTINUED) |
| (Dollars in millions) |
| | | December 31, | December 31, |
| | | 2014 | 2013 |
| LIABILITIES AND EQUITY | | | | |
| Current liabilities: | | | | |
| Short-term debt | $ | 1,733 | $ | 545 |
| Accounts payable – trade | | 1,198 | | 1,088 |
| Accounts payable – other | | 155 | | 127 |
| Due to unconsolidated affiliate | | 2 | | ― |
| Dividends and interest payable | | 282 | | 271 |
| Accrued compensation and benefits | | 373 | | 376 |
| Regulatory balancing accounts – overcollected | | ― | | 91 |
| Current portion of long-term debt | | 469 | | 1,147 |
| Fixed-price contracts and other derivatives | | 55 | | 55 |
| Customer deposits | | 153 | | 154 |
| Other | | 649 | | 515 |
| Total current liabilities | | 5,069 | | 4,369 |
| | | | | | |
| Long-term debt ($315 and $325 at December 31, 2014 and 2013, respectively, | | | | |
| related to VIE) | | 12,167 | | 11,253 |
| | | | | |
| Deferred credits and other liabilities: | | | | |
| Customer advances for construction | | 144 | | 155 |
| Pension and other postretirement benefit obligations, net of plan assets | | 1,064 | | 667 |
| Deferred income taxes | | 3,003 | | 2,804 |
| Deferred investment tax credits | | 37 | | 42 |
| Regulatory liabilities arising from removal obligations | | 2,741 | | 2,623 |
| Asset retirement obligations | | 2,048 | | 2,084 |
| Fixed-price contracts and other derivatives | | 255 | | 228 |
| Deferred credits and other | | 1,104 | | 1,169 |
| Total deferred credits and other liabilities | | 10,396 | | 9,772 |
| | | | | |
| Commitments and contingencies (Note 15) | | | | |
| | | | | |
| Equity: | | | | |
| Preferred stock (50 million shares authorized; none issued) | | ― | | ― |
| Common stock (750 million shares authorized; 246 million and 244 million | | | | |
| shares outstanding at December 31, 2014 and 2013, respectively; no par value) | | 2,484 | | 2,409 |
| Retained earnings | | 9,339 | | 8,827 |
| Accumulated other comprehensive income (loss) | | (497) | | (228) |
| Total Sempra Energy shareholders’ equity | | 11,326 | | 11,008 |
| Preferred stock of subsidiary | | 20 | | 20 |
| Other noncontrolling interests | | 754 | | 822 |
| Total equity | | 12,100 | | 11,850 |
| Total liabilities and equity | $ | 39,732 | $ | 37,244 |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | |
| Net income | $ | 1,262 | $ | 1,088 | $ | 920 |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 1,156 | | 1,113 | | 1,090 |
| Deferred income taxes and investment tax credits | | 146 | | 334 | | (43) |
| Gain on sale of equity interests and assets | | (62) | | (114) | | (7) |
| Plant closure loss | | 6 | | 200 | | ― |
| Equity (earnings) losses | | (119) | | (55) | | 324 |
| Fixed-price contracts and other derivatives | | (25) | | (21) | | (26) |
| Other | | 108 | | 13 | | 41 |
| Net change in other working capital components | | (375) | | (620) | | (630) |
| Changes in other assets | | 19 | | (171) | | 219 |
| Changes in other liabilities | | 45 | | 17 | | 130 |
| Net cash provided by operating activities | | 2,161 | | 1,784 | | 2,018 |
| | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | |
| Expenditures for property, plant and equipment | | (3,123) | | (2,572) | | (2,956) |
| Expenditures for investments and acquisition of businesses, net of cash acquired | | (240) | | (22) | | (445) |
| Proceeds from sale of equity interests and assets, net of cash sold | | 149 | | 570 | | 74 |
| Proceeds from U.S. Treasury grants | | ― | | 238 | | ― |
| Distributions from investments | | 13 | | 152 | | 207 |
| Purchases of nuclear decommissioning and other trust assets | | (613) | | (697) | | (738) |
| Proceeds from sales by nuclear decommissioning and other trusts | | 601 | | 695 | | 733 |
| Decrease in restricted cash | | 155 | | 329 | | 196 |
| Increase in restricted cash | | (152) | | (356) | | (218) |
| Advances to unconsolidated affiliates | | (185) | | (14) | | ― |
| Repayments of advances to unconsolidated affiliate | | 18 | | ― | | ― |
| Other | | 35 | | (12) | | (11) |
| Net cash used in investing activities | | (3,342) | | (1,689) | | (3,158) |
| | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | |
| Common dividends paid | | (598) | | (606) | | (550) |
| Redemption of preferred stock of subsidiary | | ― | | (82) | | ― |
| Preferred dividends paid by subsidiaries | | (1) | | (5) | | (6) |
| Issuances of common stock | | 56 | | 62 | | 78 |
| Repurchases of common stock | | (38) | | (45) | | (16) |
| Issuances of debt (maturities greater than 90 days) | | 3,272 | | 2,081 | | 3,097 |
| Payments on debt (maturities greater than 90 days) | | (2,034) | | (1,788) | | (1,112) |
| Proceeds from sale of noncontrolling interests, net of $25 in offering costs | | ― | | 574 | | ― |
| Increase (decrease) in short-term debt, net | | 412 | | 256 | | (47) |
| Purchase of noncontrolling interests | | (74) | | ― | | (7) |
| Net distributions to noncontrolling interests | | (104) | | (69) | | (61) |
| Other | | (37) | | (40) | | (21) |
| Net cash provided by financing activities | | 854 | | 338 | | 1,355 |
| Effect of exchange rate changes on cash and cash equivalents | | (7) | | (4) | | 8 |
| | | | | | | |
| (Decrease) increase in cash and cash equivalents | | (334) | | 429 | | 223 |
| Cash and cash equivalents, January 1 | | 904 | | 475 | | 252 |
| Cash and cash equivalents, December 31 | $ | 570 | $ | 904 | $ | 475 |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| CHANGES IN OTHER WORKING CAPITAL COMPONENTS | | | | | | |
| (Excluding cash and cash equivalents, and debt due within one year) | | | | | | |
| Accounts and notes receivable | $ | 44 | $ | (273) | $ | 36 |
| Income taxes receivable, net | | 62 | | (38) | | (29) |
| Inventories | | (133) | | 116 | | (78) |
| Regulatory balancing accounts | | (317) | | (198) | | (291) |
| Regulatory assets and liabilities | | 8 | | 1 | | (6) |
| Other current assets | | (10) | | 15 | | 180 |
| Accounts and notes payable | | 109 | | (28) | | 3 |
| Other current liabilities | | (138) | | (215) | | (445) |
| Net change in other working capital components | $ | (375) | $ | (620) | $ | (630) |
| | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | | | | | | |
| Interest payments, net of amounts capitalized | $ | 536 | $ | 544 | $ | 458 |
| Income tax payments, net of refunds | | 102 | | 120 | | 130 |
| | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES | | | | | | |
| Acquisition of businesses: | | | | | | |
| Assets acquired | $ | ― | $ | 13 | $ | 29 |
| Cash paid, net of cash acquired | | ― | | (11) | | (19) |
| Liabilities assumed | $ | ― | $ | 2 | $ | 10 |
| | | | | | | | |
| Nuclear facility plant reclassified to regulatory asset, net of depreciation and amortization | $ | ― | $ | 512 | $ | ― |
| Accrued capital expenditures | | 433 | | 437 | | 357 |
| Increase in capital lease obligations for investment in property, plant and equipment | | 60 | | ― | | ― |
| Financing of build-to-suit property | | 61 | | 14 | | ― |
| Capital expenditures recoverable by U.S. Treasury grants receivable(1) | | ― | | 3 | | 213 |
| Sequestration of U.S. Treasury grants receivable | | ― | | (23) | | ― |
| Dividends declared but not paid | | 166 | | 157 | | 150 |
| (1) | Cash grants; the 2012 amount excludes $45 million previously recorded in 2011 as investment tax credits. | | |
| See Notes to Consolidated Financial Statements. |
| SEMPRA ENERGY |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| (Dollars in millions) |
| | | Years ended December 31, 2014, 2013 and 2012 |
| | | | | | | Deferred | | | | |
| | | | | | | compen- | Accumulated | | | |
| | | | | | | sation | other | Sempra | | |
| | | | | | | relating | compre- | Energy | Non- | |
| | | Common | Retained | to | hensive | shareholders’ | controlling | Total |
| | | stock | earnings | ESOP | income (loss) | equity | interests | equity |
| Balance at December 31, 2011 | $ | 2,104 | $ | 8,162 | $ | (2) | $ | (489) | $ | 9,775 | $ | 403 | $ | 10,178 |
| | | | | | | | | | | | | | | |
| Net income | | | | 865 | | | | | | 865 | | 55 | | 920 |
| Other comprehensive income | | | | | | | | 113 | | 113 | | 4 | | 117 |
| | | | | | | | | | | | | | | | |
| Share-based compensation expense | | 44 | | | | | | | | 44 | | | | 44 |
| Common stock dividends declared | | | | (580) | | | | | | (580) | | | | (580) |
| Preferred dividends of subsidiaries | | | | (6) | | | | | | (6) | | | | (6) |
| Issuance of common stock | | 78 | | | | | | | | 78 | | | | 78 |
| Repurchases of common stock | | (16) | | | | | | | | (16) | | | | (16) |
| Common stock released from ESOP | | 7 | | | | 2 | | | | 9 | | | | 9 |
| Distributions to noncontrolling interests | | | | | | | | | | | | (62) | | (62) |
| Equity contributed by noncontrolling interests | | | | | | | | | | | | 8 | | 8 |
| Purchase of noncontrolling interests in | | | | | | | | | | | | | | |
| subsidiary | | | | | | | | | | | | (7) | | (7) |
| Balance at December 31, 2012 | | 2,217 | | 8,441 | | ― | | (376) | | 10,282 | | 401 | | 10,683 |
| | | | | | | | | | | | | | | | |
| Net income | | | | 1,009 | | | | | | 1,009 | | 79 | | 1,088 |
| Other comprehensive income (loss) | | | | | | | | 148 | | 148 | | (8) | | 140 |
| | | | | | | | | | | | | | | | |
| Share-based compensation expense | | 40 | | | | | | | | 40 | | | | 40 |
| Common stock dividends declared | | | | (615) | | | | | | (615) | | | | (615) |
| Preferred dividends of subsidiaries | | | | (5) | | | | | | (5) | | | | (5) |
| Issuance of common stock | | 62 | | | | | | | | 62 | | | | 62 |
| Repurchases of common stock | | (45) | | | | | | | | (45) | | | | (45) |
| Sale of noncontrolling interests, net of | | | | | | | | | | | | | | |
| offering costs | | 135 | | | | | | | | 135 | | 439 | | 574 |
| Distributions to noncontrolling interests | | | | | | | | | | | | (69) | | (69) |
| Call premium on preferred stock | | | | | | | | | | | | | | |
| of subsidiary | | | | (3) | | | | | | (3) | | | | (3) |
| Balance at December 31, 2013 | | 2,409 | | 8,827 | | ― | | (228) | | 11,008 | | 842 | | 11,850 |
| | | | | | | | | | | | | | | | |
| Net income | | | | 1,162 | | | | | | 1,162 | | 100 | | 1,262 |
| Other comprehensive loss | | | | | | | | (269) | | (269) | | (21) | | (290) |
| | | | | | | | | | | | | | | |
| Share-based compensation expense | | 48 | | | | | | | | 48 | | | | 48 |
| Common stock dividends declared | | | | (649) | | | | | | (649) | | | | (649) |
| Preferred dividends of subsidiary | | | | (1) | | | | | | (1) | | | | (1) |
| Issuance of common stock | | 97 | | | | | | | | 97 | | | | 97 |
| Repurchases of common stock | | (38) | | | | | | | | (38) | | | | (38) |
| Distributions to noncontrolling interests | | | | | | | | | | | | (107) | | (107) |
| Equity contributed by noncontrolling interests | | | | | | | | | | | | 1 | | 1 |
| Purchase of noncontrolling interests in | | | | | | | | | | | | | | |
| subsidiary | | (32) | | | | | | | | (32) | | (41) | | (73) |
| Balance at December 31, 2014 | $ | 2,484 | $ | 9,339 | $ | ― | $ | (497) | $ | 11,326 | $ | 774 | $ | 12,100 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Operating revenues | | | | | | |
| Electric | $ | 3,785 | $ | 3,537 | $ | 3,226 |
| Natural gas | | 544 | | 529 | | 468 |
| Total operating revenues | | 4,329 | | 4,066 | | 3,694 |
| Operating expenses | | | | | | |
| Cost of electric fuel and purchased power | | 1,309 | | 1,019 | | 892 |
| Cost of natural gas | | 208 | | 204 | | 151 |
| Operation and maintenance | | 1,076 | | 1,157 | | 1,154 |
| Depreciation and amortization | | 530 | | 494 | | 490 |
| Franchise fees and other taxes | | 241 | | 210 | | 198 |
| Plant closure loss | | 6 | | 200 | | ― |
| Total operating expenses | | 3,370 | | 3,284 | | 2,885 |
| Operating income | | 959 | | 782 | | 809 |
| Other income, net | | 40 | | 40 | | 69 |
| Interest income | | ― | | 1 | | ― |
| Interest expense | | (202) | | (197) | | (173) |
| Income before income taxes | | 797 | | 626 | | 705 |
| Income tax expense | | (270) | | (191) | | (190) |
| Net income | | 527 | | 435 | | 515 |
| Earnings attributable to noncontrolling interest | | (20) | | (24) | | (26) |
| Earnings | | 507 | | 411 | | 489 |
| Call premium on preferred stock | | ― | | (3) | | ― |
| Preferred dividend requirements | | ― | | (4) | | (5) |
| Earnings attributable to common shares | $ | 507 | $ | 404 | $ | 484 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| (Dollars in millions) | | | | |
| | | Years ended December 31, 2014, 2013 and 2012 |
| | | SDG&E shareholder's equity | | | | |
| | | Pretax | Income tax | Net-of-tax | Noncontrolling | |
| | | amount | expense | amount | interest (after-tax) | Total |
| 2014: | | | | | | | | | | |
| Net income | $ | 777 | $ | (270) | $ | 507 | $ | 20 | $ | 527 |
| Other comprehensive income (loss): | | | | | | | | | | |
| Pension and other postretirement benefits | | (5) | | 2 | | (3) | | ― | | (3) |
| Financial instruments | | ― | | ― | | ― | | 2 | | 2 |
| Total other comprehensive income (loss) | | (5) | | 2 | | (3) | | 2 | | (1) |
| Comprehensive income | $ | 772 | $ | (268) | $ | 504 | $ | 22 | $ | 526 |
| 2013: | | | | | | | | | | |
| Net income | $ | 602 | $ | (191) | $ | 411 | $ | 24 | $ | 435 |
| Other comprehensive income: | | | | | | | | | | |
| Pension and other postretirement benefits | | 3 | | (1) | | 2 | | ― | | 2 |
| Financial instruments | | ― | | ― | | ― | | 17 | | 17 |
| Total other comprehensive income | | 3 | | (1) | | 2 | | 17 | | 19 |
| Comprehensive income | $ | 605 | $ | (192) | $ | 413 | $ | 41 | $ | 454 |
| 2012: | | | | | | | | | | |
| Net income | $ | 679 | $ | (190) | $ | 489 | $ | 26 | $ | 515 |
| Other comprehensive loss: | | | | | | | | | | |
| Pension and other postretirement benefits | | (1) | | ― | | (1) | | ― | | (1) |
| Financial instruments | | ― | | ― | | ― | | (11) | | (11) |
| Total other comprehensive loss | | (1) | | ― | | (1) | | (11) | | (12) |
| Comprehensive income | $ | 678 | $ | (190) | $ | 488 | $ | 15 | $ | 503 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED BALANCE SHEETS |
| (Dollars in millions) |
| | | December 31, | December 31, |
| | | 2014 | 2013 |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | $ | 8 | $ | 27 |
| Restricted cash | | 8 | | 6 |
| Accounts receivable – trade, net | | 285 | | 266 |
| Accounts receivable – other, net | | 35 | | 28 |
| Due from unconsolidated affiliates | | 1 | | 1 |
| Income taxes receivable | | ― | | 32 |
| Deferred income taxes | | ― | | 103 |
| Inventories | | 73 | | 86 |
| Regulatory balancing accounts – undercollected | | 711 | | 556 |
| Regulatory assets | | 54 | | 29 |
| Fixed-price contracts and other derivatives | | 44 | | 61 |
| Other | | 125 | | 75 |
| Total current assets | | 1,344 | | 1,270 |
| | | | | | |
| Other assets: | | | | |
| Restricted cash | | 11 | | 25 |
| Deferred taxes recoverable in rates | | 824 | | 788 |
| Regulatory assets | | 1,086 | | 1,160 |
| Nuclear decommissioning trusts | | 1,131 | | 1,034 |
| Sundry | | 282 | | 254 |
| Total other assets | | 3,334 | | 3,261 |
| | | | | | |
| Property, plant and equipment: | | | | |
| Property, plant and equipment | | 15,478 | | 14,346 |
| Less accumulated depreciation and amortization | | (3,860) | | (3,500) |
| Property, plant and equipment, net ($410 and $438 at December 31, 2014 | | | | |
| and 2013, respectively, related to VIE) | | 11,618 | | 10,846 |
| Total assets | $ | 16,296 | $ | 15,377 |
| See Notes to Consolidated Financial Statements. | | | | |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED BALANCE SHEETS (CONTINUED) |
| (Dollars in millions) |
| | | December 31, | December 31, |
| | | 2014 | 2013 |
| LIABILITIES AND EQUITY | | | | |
| Current liabilities: | | | | |
| Short-term debt | $ | 246 | $ | 59 |
| Accounts payable | | 441 | | 420 |
| Due to unconsolidated affiliates | | 21 | | 39 |
| Income taxes payable | | 30 | | ― |
| Deferred income taxes | | 53 | | ― |
| Interest payable | | 40 | | 39 |
| Accrued compensation and benefits | | 124 | | 113 |
| Current portion of long-term debt | | 365 | | 29 |
| Asset retirement obligation | | 120 | | 51 |
| Fixed-price contracts and other derivatives | | 40 | | 38 |
| Customer deposits | | 71 | | 71 |
| Other | | 237 | | 220 |
| Total current liabilities | | 1,788 | | 1,079 |
| Long-term debt ($315 and $325 at December 31, 2014 and 2013, respectively, | | | | |
| related to VIE) | | 4,319 | | 4,525 |
| | | | | | |
| Deferred credits and other liabilities: | | | | |
| Customer advances for construction | | 41 | | 34 |
| Pension and other postretirement benefit obligations, net of plan assets | | 216 | | 132 |
| Deferred income taxes | | 2,121 | | 2,021 |
| Deferred investment tax credits | | 22 | | 24 |
| Regulatory liabilities arising from removal obligations | | 1,557 | | 1,403 |
| Asset retirement obligations | | 754 | | 861 |
| Fixed-price contracts and other derivatives | | 153 | | 175 |
| Deferred credits and other | | 333 | | 404 |
| Total deferred credits and other liabilities | | 5,197 | | 5,054 |
| | | | | | |
| Commitments and contingencies (Note 15) | | | | |
| | | | | | |
| Equity: | | | | |
| Common stock (255 million shares authorized; 117 million shares outstanding; | | | | |
| no par value) | | 1,338 | | 1,338 |
| Retained earnings | | 3,606 | | 3,299 |
| Accumulated other comprehensive income (loss) | | (12) | | (9) |
| Total SDG&E shareholder’s equity | | 4,932 | | 4,628 |
| Noncontrolling interest | | 60 | | 91 |
| Total equity | | 4,992 | | 4,719 |
| Total liabilities and equity | $ | 16,296 | $ | 15,377 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | |
| Net income | $ | 527 | $ | 435 | $ | 515 |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 530 | | 494 | | 490 |
| Deferred income taxes and investment tax credits | | 223 | | 171 | | 285 |
| Plant closure loss | | 6 | | 200 | | ― |
| Fixed-price contracts and other derivatives | | (6) | | (8) | | (12) |
| Other | | (23) | | (37) | | (63) |
| Changes in other assets | | 191 | | (150) | | 201 |
| Changes in other liabilities | | 18 | | 19 | | 129 |
| Changes in working capital components: | | | | | | |
| Accounts receivable | | (47) | | (40) | | 12 |
| Due to/from affiliates, net | | (10) | | 38 | | 29 |
| Inventories | | 4 | | (14) | | ― |
| Other current assets | | (16) | | 7 | | 208 |
| Income taxes | | 35 | | (50) | | 85 |
| Accounts payable | | (23) | | 50 | | (42) |
| Regulatory balancing accounts | | (208) | | (140) | | (322) |
| Interest payable | | ― | | 4 | | 5 |
| Other current liabilities | | (104) | | (260) | | (419) |
| Net cash provided by operating activities | | 1,097 | | 719 | | 1,101 |
| | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | |
| Expenditures for property, plant and equipment | | (1,100) | | (978) | | (1,237) |
| Purchases of nuclear decommissioning trust assets | | (609) | | (692) | | (732) |
| Proceeds from sales by nuclear decommissioning trusts | | 601 | | 685 | | 723 |
| Proceeds from sale of assets | | ― | | 11 | | ― |
| Decrease in restricted cash | | 96 | | 82 | | 92 |
| Increase in restricted cash | | (84) | | (81) | | (81) |
| Expenditures related to long-term service agreement | | (30) | | ― | | ― |
| Net cash used in investing activities | | (1,126) | | (973) | | (1,235) |
| | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | |
| Common dividends paid | | (200) | | ― | | ― |
| Redemption of preferred stock | | ― | | (82) | | ― |
| Preferred dividends paid | | ― | | (5) | | (5) |
| Issuances of long-term debt | | 100 | | 450 | | 249 |
| Payments on long-term debt | | (24) | | (199) | | (10) |
| Capital distributions made by Otay Mesa VIE | | (53) | | (26) | | (40) |
| Increase in short-term debt, net | | 187 | | 59 | | ― |
| Other | | ― | | (3) | | (2) |
| Net cash provided by financing activities | | 10 | | 194 | | 192 |
| (Decrease) increase in cash and cash equivalents | | (19) | | (60) | | 58 |
| Cash and cash equivalents, January 1 | | 27 | | 87 | | 29 |
| Cash and cash equivalents, December 31 | $ | 8 | $ | 27 | $ | 87 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | | | | | | |
| Interest payments, net of amounts capitalized | $ | 196 | $ | 187 | $ | 162 |
| Income tax (refunds) payments, net | | (4) | | 84 | | (242) |
| | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES | | | | | | |
| Nuclear facility plant reclassified to regulatory asset, net of depreciation | | | | | | |
| and amortization | $ | ― | $ | 512 | $ | ― |
| Accrued capital expenditures | | 217 | | 182 | | 153 |
| Increase in capital lease obligations for investment in property, plant and equipment | | 60 | | ― | | ― |
| Dividends declared but not paid | | ― | | ― | | 1 |
| See Notes to Consolidated Financial Statements. |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY |
| (Dollars in millions) |
| | Years ended December 2014, 2013 and 2012 |
| | | | | Accumulated | | | |
| | | | | other | SDG&E | | |
| | Common | Retained | comprehensive | shareholder’s | Noncontrolling | Total |
| | stock | earnings | income (loss) | equity | interest | equity |
| Balance at December 31, 2011 | $ | 1,338 | $ | 2,411 | $ | (10) | $ | 3,739 | $ | 102 | $ | 3,841 |
| | | | | | | | | | | | | |
| Net income | | | | 489 | | | | 489 | | 26 | | 515 |
| Other comprehensive loss | | | | | | (1) | | (1) | | (11) | | (12) |
| | | | | | | | | | | | | |
| Preferred stock dividends declared | | | | (5) | | | | (5) | | | | (5) |
| Distributions to noncontrolling interest | | | | | | | | | | (41) | | (41) |
| Balance at December 31, 2012 | | 1,338 | | 2,895 | | (11) | | 4,222 | | 76 | | 4,298 |
| | | | | | | | | | | | | |
| Net income | | | | 411 | | | | 411 | | 24 | | 435 |
| Other comprehensive income | | | | | | 2 | | 2 | | 17 | | 19 |
| | | | | | | | | | | | | |
| Preferred stock dividends declared | | | | (4) | | | | (4) | | | | (4) |
| Distributions to noncontrolling interest | | | | | | | | | | (26) | | (26) |
| Call premium on preferred stock | | | | (3) | | | | (3) | | | | (3) |
| Balance at December 31, 2013 | | 1,338 | | 3,299 | | (9) | | 4,628 | | 91 | | 4,719 |
| | | | | | | | | | | | | |
| Net income | | | | 507 | | | | 507 | | 20 | | 527 |
| Other comprehensive (loss) income | | | | | | (3) | | (3) | | 2 | | (1) |
| | | | | | | | | | | | | |
| Common stock dividends declared | | | | (200) | | | | (200) | | | | (200) |
| Distributions to noncontrolling interest | | | | | | | | | | (53) | | (53) |
| Balance at December 31, 2014 | $ | 1,338 | $ | 3,606 | $ | (12) | $ | 4,932 | $ | 60 | $ | 4,992 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| | | | | | | |
| Operating revenues | $ | 3,855 | $ | 3,736 | $ | 3,282 |
| Operating expenses | | | | | | |
| Cost of natural gas | | 1,449 | | 1,362 | | 1,074 |
| Operation and maintenance | | 1,321 | | 1,324 | | 1,304 |
| Depreciation and amortization | | 431 | | 383 | | 362 |
| Franchise fees and other taxes | | 133 | | 128 | | 122 |
| Total operating expenses | | 3,334 | | 3,197 | | 2,862 |
| Operating income | | 521 | | 539 | | 420 |
| Other income, net | | 20 | | 11 | | 17 |
| Interest expense | | (69) | | (69) | | (68) |
| Income before income taxes | | 472 | | 481 | | 369 |
| Income tax expense | | (139) | | (116) | | (79) |
| Net income | | 333 | | 365 | | 290 |
| Preferred dividend requirements | | (1) | | (1) | | (1) |
| Earnings attributable to common shares | $ | 332 | $ | 364 | $ | 289 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME |
| (Dollars in millions) |
| | | Years ended December 31, 2014, 2013 and 2012 |
| | | Pretax | Income tax | Net-of-tax |
| | | amount | (expense) benefit | amount |
| 2014: | | | | | | |
| Net Income/Comprehensive income | $ | 472 | $ | (139) | $ | 333 |
| 2013: | | | | | | |
| Net income | $ | 481 | $ | (116) | $ | 365 |
| Other comprehensive income (loss): | | | | | | |
| Pension and other postretirement benefits | | (2) | | 1 | | (1) |
| Financial instruments | | 1 | | ― | | 1 |
| Total other comprehensive loss | | (1) | | 1 | | ― |
| Comprehensive income | $ | 480 | $ | (115) | $ | 365 |
| 2012: | | | | | | |
| Net income | $ | 369 | $ | (79) | $ | 290 |
| Other comprehensive income: | | | | | | |
| Pension and other postretirement benefits | | 5 | | (3) | | 2 |
| Financial instruments | | 2 | | (1) | | 1 |
| Total other comprehensive income | | 7 | | (4) | | 3 |
| Comprehensive income | $ | 376 | $ | (83) | $ | 293 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED BALANCE SHEETS |
| (Dollars in millions) |
| | December 31, | December 31, |
| | 2014 | 2013 |
| ASSETS | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | $ | 85 | $ | 27 |
| Accounts receivable – trade, net | | 586 | | 595 |
| Accounts receivable – other, net | | 51 | | 97 |
| Due from unconsolidated affiliates | | 4 | | 21 |
| Income taxes receivable | | 5 | | 25 |
| Inventories | | 181 | | 69 |
| Regulatory balancing accounts – undercollected | | 35 | | ― |
| Regulatory assets | | 5 | | 5 |
| Other | | 36 | | 34 |
| Total current assets | | 988 | | 873 |
| | | | | |
| Other assets: | | | | |
| Regulatory assets arising from pension obligations | | 617 | | 326 |
| Other regulatory assets | | 472 | | 262 |
| Other postretirement benefit assets, net of plan liabilities | | 4 | | 95 |
| Sundry | | 136 | | 124 |
| Total other assets | | 1,229 | | 807 |
| | | | | |
| Property, plant and equipment: | | | | |
| Property, plant and equipment | | 12,886 | | 11,831 |
| Less accumulated depreciation and amortization | | (4,642) | | (4,364) |
| Property, plant and equipment, net | | 8,244 | | 7,467 |
| Total assets | $ | 10,461 | $ | 9,147 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED BALANCE SHEETS (CONTINUED) |
| (Dollars in millions) |
| | December 31, | December 31, |
| | 2014 | 2013 |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | |
| Current liabilities: | | | | |
| Short-term debt | $ | 50 | $ | 42 |
| Accounts payable – trade | | 532 | | 346 |
| Accounts payable – other | | 88 | | 79 |
| Due to unconsolidated affiliate | | 13 | | 16 |
| Deferred income taxes | | 53 | | 45 |
| Accrued compensation and benefits | | 129 | | 141 |
| Regulatory balancing accounts – overcollected | | ― | | 91 |
| Current portion of long-term debt | | ― | | 252 |
| Customer deposits | | 75 | | 75 |
| Other | | 149 | | 125 |
| Total current liabilities | | 1,089 | | 1,212 |
| | | | | |
| Long-term debt | | 1,906 | | 1,159 |
| Deferred credits and other liabilities: | | | | |
| Customer advances for construction | | 102 | | 108 |
| Pension obligation, net of plan assets | | 633 | | 339 |
| Deferred income taxes | | 1,212 | | 993 |
| Deferred investment tax credits | | 16 | | 18 |
| Regulatory liabilities arising from removal obligations | | 1,167 | | 1,205 |
| Asset retirement obligations | | 1,255 | | 1,182 |
| Deferred credits and other | | 300 | | 382 |
| Total deferred credits and other liabilities | | 4,685 | | 4,227 |
| | | | | |
| Commitments and contingencies (Note 15) | | | | |
| | | | | |
| Shareholders’ equity: | | | | |
| Preferred stock | | 22 | | 22 |
| Common stock (100 million shares authorized; 91 million shares outstanding; | | | | |
| no par value) | | 866 | | 866 |
| Retained earnings | | 1,911 | | 1,679 |
| Accumulated other comprehensive income (loss) | | (18) | | (18) |
| Total shareholders’ equity | | 2,781 | | 2,549 |
| Total liabilities and shareholders’ equity | $ | 10,461 | $ | 9,147 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | |
| Net income | $ | 333 | $ | 365 | $ | 290 |
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | |
| Depreciation and amortization | | 431 | | 383 | | 362 |
| Deferred income taxes and investment tax credits | | 130 | | 117 | | 128 |
| Other | | (7) | | (5) | | (12) |
| Changes in other assets | | (131) | | (52) | | 14 |
| Changes in other liabilities | | 29 | | (4) | | 4 |
| Changes in working capital components: | | | | | | |
| Accounts receivable | | 30 | | (113) | | 37 |
| Inventories | | (113) | | 82 | | (1) |
| Other current assets | | (3) | | 3 | | (6) |
| Accounts payable | | 156 | | (54) | | 54 |
| Income taxes | | 17 | | 51 | | (83) |
| Due to/from affiliates, net | | (1) | | (57) | | 51 |
| Regulatory balancing accounts | | (109) | | (58) | | 31 |
| Customer deposits | | ― | | (1) | | 1 |
| Other current liabilities | | 3 | | 24 | | (24) |
| Net cash provided by operating activities | | 765 | | 681 | | 846 |
| | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | |
| Expenditures for property, plant and equipment | | (1,104) | | (762) | | (639) |
| Decrease (increase) in loans to affiliate, net | | ― | | 34 | | (4) |
| Net cash used in investing activities | | (1,104) | | (728) | | (643) |
| | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | |
| Common dividends paid | | (100) | | (50) | | (250) |
| Preferred dividends paid | | (1) | | (1) | | (1) |
| Issuances of long-term debt | | 747 | | ― | | 348 |
| Payments on long-term debt | | (250) | | ― | | (250) |
| Debt issuance costs | | (7) | | ― | | (3) |
| Increase in short-term debt, net | | 8 | | 42 | | ― |
| Net cash provided by (used in) financing activities | | 397 | | (9) | | (156) |
| | | | | | | |
| Increase (decrease) in cash and cash equivalents | | 58 | | (56) | | 47 |
| Cash and cash equivalents, January 1 | | 27 | | 83 | | 36 |
| Cash and cash equivalents, December 31 | $ | 85 | $ | 27 | $ | 83 |
| | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | | | | | | |
| Interest payments, net of amounts capitalized | $ | 62 | $ | 65 | $ | 62 |
| Income tax (refunds) payments, net | | (10) | | (52) | | 16 |
| | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY | | | | | | |
| Accrued capital expenditures | $ | 168 | $ | 130 | $ | 115 |
| See Notes to Consolidated Financial Statements. |
| SOUTHERN CALIFORNIA GAS COMPANY |
| CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY |
| (Dollars in millions) |
| | Years ended December 31, 2014, 2013 and 2012 |
| | | | | | | Accumulated | |
| | | | | | | other | Total |
| | Preferred | Common | Retained | comprehensive | shareholders’ |
| | stock | stock | earnings | income (loss) | equity |
| Balance at December 31, 2011 | $ | 22 | $ | 866 | $ | 1,326 | $ | (21) | $ | 2,193 |
| | | | | | | | | | | |
| Net income | | | | | | 290 | | | | 290 |
| Other comprehensive income | | | | | | | | 3 | | 3 |
| | | | | | | | | | | |
| Preferred stock dividends declared | | | | | | (1) | | | | (1) |
| Common stock dividends declared | | | | | | (250) | | | | (250) |
| Balance at December 31, 2012 | | 22 | | 866 | | 1,365 | | (18) | | 2,235 |
| | | | | | | | | | | |
| Net income | | | | | | 365 | | | | 365 |
| | | | | | | | | | | |
| Preferred stock dividends declared | | | | | | (1) | | | | (1) |
| Common stock dividends declared | | | | | | (50) | | | | (50) |
| Balance at December 31, 2013 | | 22 | | 866 | | 1,679 | | (18) | | 2,549 |
| | | | | | | | | | | |
| Net income | | | | | | 333 | | | | 333 |
| | | | | | | | | | | |
| Preferred stock dividends declared | | | | | | (1) | | | | (1) |
| Common stock dividends declared | | | | | | (100) | | | | (100) |
| Balance at December 31, 2014 | $ | 22 | $ | 866 | $ | 1,911 | $ | (18) | $ | 2,781 |
| See Notes to Consolidated Financial Statements. |
SEMPRA ENERGY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES AND OTHER FINANCIAL DATA
PRINCIPLES OF CONSOLIDATION
Sempra Energy
Sempra Energy’s 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 16.
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 below under “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 Notes 3 and 4.
SDG&E
SDG&E’s Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss below 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’ Consolidated Financial Statements include its accounts and the de minimis 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.
Regulated Operations
Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru and their subsidiaries. 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 the provisions of accounting principles generally accepted in the United States of America (U.S. GAAP) governing regulated operations, as we discuss below under “Regulatory Matters.” We discuss revenue recognition at our utilities in “Revenues–Utilities” below.
Use of Estimates in the Preparation of the Financial Statements
We have prepared our Consolidated Financial Statements in conformity with U.S. GAAP. This requires us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes, including the disclosure of contingent assets and liabilities at the date of the financial statements. Although we believe the estimates and assumptions are reasonable, actual amounts ultimately may differ significantly from those estimates.
Subsequent Events
We evaluated events and transactions that occurred after December 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.
Effects of Regulation
The accounting policies of our regulated utility subsidiaries in California, SDG&E and SoCalGas, conform with U.S. GAAP for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
The California Utilities prepare their financial statements in accordance with U.S. GAAP provisions governing regulated operations. Under these provisions, a regulated utility records regulatory assets, which are generally costs that would otherwise be charged to expense, if it is probable that, through the ratemaking process, the utility will recover those assets from customers. To the extent that recovery is no longer probable, the related regulatory assets are written off. Regulatory liabilities generally represent amounts collected from customers in advance of the actual expenditure by the utility. If the actual expenditures are less than amounts previously collected from ratepayers, the excess would be refunded to customers, generally by reducing future rates. Regulatory liabilities may also arise from other transactions such as unrealized gains on fixed price contracts and other derivatives or certain deferred income tax benefits that are passed through to customers in future rates. In addition, the California Utilities record regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other transaction of net allowable costs be given to customers over future periods.
Determining probability of recovery requires significant judgment by management and may include, but is not limited to, consideration of:
| § | the nature of the event giving rise to the assessment; |
| § | existing statutes and regulatory code; |
| § | regulatory principles and analogous regulatory actions; |
| § | testimony presented in regulatory hearings; |
| § | proposed regulatory decisions; |
| § | final regulatory orders; |
| § | a commission-authorized mechanism established for the accumulation of costs; |
| § | status of applications for rehearings or state court appeals; |
| § | specific approval from a commission; and |
Our other natural gas distribution utilities, Mobile Gas, Willmut Gas and Ecogas, also apply U.S. GAAP for regulated utilities to their operations.
We provide information concerning regulatory assets and liabilities below in “Regulatory Balancing Accounts” and “Regulatory Assets and Liabilities” and in Notes 13 and 14.
Regulatory Balancing Accounts
The following table summarizes our regulatory balancing accounts at December 31.
| SUMMARY OF REGULATORY BALANCING ACCOUNTS AT DECEMBER 31 |
| (Dollars in millions) |
| | | Sempra Energy | | |
| | | Consolidated | SDG&E | SoCalGas |
| | | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| Current: | | | | | | | | | | | | |
| Overcollected | $ | (1,730) | $ | (1,077) | $ | (1,195) | $ | (645) | $ | (535) | $ | (432) |
| Undercollected | | 2,476 | | 1,542 | | 1,906 | | 1,201 | | 570 | | 341 |
| Net current receivable (payable)(1) | | 746 | | 465 | | 711 | | 556 | | 35 | | (91) |
| Noncurrent: | | | | | | | | | | | | |
| Undercollected(2) | | 173 | | 213 | | ― | | 161 | | 173 | | 52 |
| Total net receivable (payable)(1) | $ | 919 | $ | 678 | $ | 711 | $ | 717 | $ | 208 | $ | (39) |
| (1) | At December 31, 2013, the net receivable at SDG&E and the net payable at SoCalGas are shown separately on Sempra Energy's Consolidated Balance Sheet. |
| (2) | Long-term undercollected balance included in Regulatory Assets (long-term) on the Consolidated Balance Sheets. |
Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs, primarily commodity costs. Amounts in the balancing accounts are recoverable (receivable) or refundable (payable) in future rates, subject to CPUC approval. Balancing account treatment eliminates the impact on earnings from variances in the covered costs from authorized amounts. Absent balancing account treatment, variations in the cost of fuel supply and certain operating and maintenance costs from amounts approved by the CPUC would increase volatility in utility earnings.
We provide additional information about regulatory matters in Notes 13, 14 and 15.
Regulatory Assets and Liabilities
We show the details of regulatory assets and liabilities in the following table, and discuss each of them separately below.
| REGULATORY ASSETS (LIABILITIES) AT DECEMBER 31 |
| (Dollars in millions) |
| | | 2014 | 2013 |
| SDG&E: | | | | |
| Fixed-price contracts and other derivatives | $ | 76 | $ | 58 |
| Costs related to SONGS plant closure | | 308 | | 303 |
| Costs related to wildfire litigation | | 373 | | 330 |
| Deferred taxes recoverable in rates | | 824 | | 788 |
| Pension and other postretirement benefit obligations | | 171 | | 106 |
| Removal obligations(1) | | (1,557) | | (1,403) |
| Unamortized loss on reacquired debt | | 12 | | 14 |
| Environmental costs | | 27 | | 20 |
| Legacy meters | | 47 | | 62 |
| Sunrise Powerlink fire mitigation | | 116 | | 115 |
| Other | | 10 | | 15 |
| Total SDG&E | | 407 | | 408 |
| SoCalGas: | | | | |
| Pension and other postretirement benefit obligations | | 613 | | 231 |
| Employee benefit costs | | 52 | | 51 |
| Removal obligations(1) | | (1,167) | | (1,205) |
| Deferred taxes recoverable in rates | | 195 | | 110 |
| Unamortized loss on reacquired debt | | 12 | | 14 |
| Environmental costs | | 22 | | 14 |
| Workers’ compensation | | 23 | | 26 |
| Total SoCalGas | | (250) | | (759) |
| Other Sempra Energy: | | | | |
| Sempra Natural Gas | | (17) | | (11) |
| Sempra Mexico | | 23 | | 8 |
| Total Other Sempra Energy | | 6 | | (3) |
| Total Sempra Energy Consolidated | $ | 163 | $ | (354) |
| (1) | Related to obligations discussed below in “Asset Retirement Obligations.” |
| NET REGULATORY ASSETS (LIABILITIES) AS PRESENTED ON THE CONSOLIDATED BALANCE SHEETS AT DECEMBER 31 |
| (Dollars in millions) |
| | | 2014 | | 2013 |
| | | Sempra | | | | Sempra | | |
| | | Energy | | | | Energy | | |
| | | Consolidated | SDG&E | SoCalGas | | Consolidated | SDG&E | SoCalGas |
| Current regulatory assets(1) | $ | 59 | $ | 54 | $ | 5 | | $ | 38 | $ | 29 | $ | 5 |
| Noncurrent regulatory assets(2) | | 2,858 | | 1,910 | | 916 | | | 2,335 | | 1,787 | | 536 |
| Current regulatory liabilities(3) | | (7) | | ― | | ― | | | (7) | | (5) | | ― |
| Noncurrent regulatory liabilities(4) | | (2,747) | | (1,557) | | (1,171) | | | (2,720) | | (1,403) | | (1,300) |
| Total | $ | 163 | $ | 407 | $ | (250) | | $ | (354) | $ | 408 | $ | (759) |
| (1) | At Sempra Energy Consolidated, included in Other Current Assets. |
| (2) | Excludes long-term undercollected balancing accounts at December 31, 2014 and 2013, of $173 million and $213 million at Sempra Energy, none and $161 million at SDG&E, and $173 million and $52 million at SoCalGas, respectively, recorded in Regulatory Assets (long-term). |
| (3) | Included in Other Current Liabilities. |
| (4) | At December 31, 2014 and 2013, $6 million and $97 million, respectively, at Sempra Energy Consolidated and $4 million and $95 million, respectively, at SoCalGas is included in Deferred Credits and Other. |
In the tables above:
| § | Regulatory assets arising from fixed-price contracts and other derivatives are offset by corresponding liabilities arising from purchased power and natural gas commodity and transportation contracts. The regulatory asset is increased/decreased based on changes in the fair market value of the contracts. It is also reduced as payments are made for commodities and services under these contracts. |
| § | Regulatory assets arising from the San Onofre Nuclear Generating Station (SONGS) plant closure are associated with SDG&E’s investment in SONGS as of the plant closure date and the cost of operations since Units 2 and 3 were taken offline, as we discuss further in Note 13. |
| § | Regulatory assets arising from costs related to wildfire litigation are costs in excess of liability insurance coverage and amounts recovered from third parties, as we discuss in Note 14 under “Excess Wildfire Claims Cost Recovery” and Note 15 under “SDG&E — 2007 Wildfire Litigation.” |
| § | Deferred taxes recoverable in rates are based on current regulatory ratemaking and income tax laws. SDG&E and SoCalGas expect to recover net regulatory assets related to deferred income taxes over the lives of the assets that give rise to the accumulated deferred income tax liabilities. |
| § | Regulatory assets/liabilities related to pension and other postretirement benefit obligations are offset by corresponding liabilities/assets and are being recovered in rates as the plans are funded. |
| § | Regulatory assets related to unamortized losses on reacquired debt are recovered over the remaining amortization periods of the losses on reacquired debt. These periods range from 5 months to 13 years for SDG&E and from 7 years to 11 years for SoCalGas. |
| § | Regulatory assets related to environmental costs represent the portion of our environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. We expect this amount to be recovered in future rates as expenditures are made. |
| § | The regulatory asset related to the legacy meters removed from service and replaced under the Smart Meter Program is their undepreciated value. SDG&E is recovering this asset over a remaining 3-year period in ratebase. |
| § | The regulatory asset related to Sunrise Powerlink fire mitigation is offset by a corresponding liability for the funding of a trust to cover the mitigation costs. SDG&E expects to recover the regulatory asset in rates as the trust is funded over a remaining 55-year period. We discuss the trust further in Note 15. |
We apply recurring fair value measurements to certain assets and liabilities, primarily nuclear decommissioning and benefit plan trust assets and other miscellaneous derivatives. “Fair value” is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
A fair value measurement reflects the assumptions market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risk inherent in a particular valuation technique (such as a pricing model) and the risks inherent in the inputs to the model. Also, we consider an issuer’s credit standing when measuring its liabilities at fair value.
We establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 financial instruments primarily consist of listed equities, U.S. government treasury securities and exchange-traded derivatives.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including:
| § | quoted forward prices for commodities |
| § | current market and contractual prices for the underlying instruments |
| § | other relevant economic measures |
Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our financial instruments in this category include domestic corporate bonds, municipal bonds and other foreign bonds, primarily in the Nuclear Decommissioning Trusts and in our pension and postretirement benefit plans, and non-exchange-traded derivatives such as interest rate instruments and over-the-counter (OTC) forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value from the perspective of a market participant. Substantially all of our Level 3 financial instruments are related to congestion revenue rights (CRRs) at SDG&E.
CASH AND CASH EQUIVALENTS
Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase.
Restricted cash at Sempra Energy, including amounts at SDG&E discussed below, was $40 million and $49 million at December 31, 2014 and 2013, respectively. Of this, $11 million and $24 million was classified as current and $29 million and $25 million was classified as noncurrent at December 31, 2014 and 2013, respectively.
SDG&E had $19 million and $31 million of restricted cash at December 31, 2014 and 2013, respectively, which represents funds held by a trustee for Otay Mesa VIE (see “Variable Interest Entities—Otay Mesa VIE” below) to pay certain operating costs. Of this, $8 million and $6 million was classified as current and $11 million and $25 million was classified as noncurrent at December 31, 2014 and 2013, respectively.
Sempra Mexico had restricted cash of $18 million classified as noncurrent and $12 million classified as current at December 31, 2014 and 2013, respectively, representing funds to pay for rights of way, license fees, permits, topographic surveys and other costs pursuant to trust agreements related to a pipeline project.
Sempra Renewables had restricted cash of $3 million and $6 million classified as current at December 31, 2014 and 2013, respectively, primarily representing funds held in accordance with debt agreements at Copper Mountain Solar 1.
We record allowances for the collection of trade and other accounts and notes receivable, which include allowances for doubtful customer accounts and for other receivables. We show the changes in these allowances in the table below:
| COLLECTION ALLOWANCES |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | | | | | | |
| Allowances for collection of receivables at January 1 | $ | 29 | $ | 31 | $ | 29 |
| Provisions for uncollectible accounts | | 25 | | 16 | | 21 |
| Write-offs of uncollectible accounts | | (20) | | (18) | | (19) |
| Allowances for collection of receivables at December 31 | $ | 34 | $ | 29 | $ | 31 |
| SDG&E | | | | | | |
| Allowances for collection of receivables at January 1 | $ | 5 | $ | 6 | $ | 6 |
| Provisions for uncollectible accounts | | 7 | | 4 | | 5 |
| Write-offs of uncollectible accounts | | (5) | | (5) | | (5) |
| Allowances for collection of receivables at December 31 | $ | 7 | $ | 5 | $ | 6 |
| SoCalGas | | | | | | |
| Allowances for collection of receivables at January 1 | $ | 12 | $ | 14 | $ | 12 |
| Provisions for uncollectible accounts | | 15 | | 7 | | 12 |
| Write-offs of uncollectible accounts | | (10) | | (9) | | (10) |
| Allowances for collection of receivables at December 31 | $ | 17 | $ | 12 | $ | 14 |
We evaluate accounts receivable collectibility using a combination of factors, including past due status based on contractual terms, trends in write-offs, the age of the receivable, counterparty creditworthiness, economic conditions and specific events, such as bankruptcies. Adjustments to the allowance for doubtful accounts are made when necessary based on the results of analysis, the aging of receivables, and historical and industry trends.
We write off accounts receivable in the period in which we deem the receivable to be uncollectible. We record recoveries of accounts receivable previously written off when it is known that they will be received.
The California Utilities value natural gas inventory by the last-in first-out (LIFO) method. As inventories are sold, differences between the LIFO valuation and the estimated replacement cost are reflected in customer rates. Materials and supplies at the California Utilities are generally valued at the lower of average cost or market.
Sempra South American Utilities, Sempra Mexico and Sempra Natural Gas value natural gas inventory and materials and supplies at the lower of average cost or market. Sempra Mexico and Sempra Natural Gas value liquefied natural gas (LNG) inventory by the first-in first-out method.
The components of inventories by segment are as follows:
| INVENTORY BALANCES AT DECEMBER 31 |
| (Dollars in millions) |
| | | Natural Gas | | LNG | Materials and supplies | Total |
| | | 2014 | 2013 | | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| SDG&E | $ | 8 | $ | 3 | $ | ― | $ | ― | $ | 65 | $ | 83 | $ | 73 | $ | 86 |
| SoCalGas | | 155 | | 42 | | ― | | ― | | 26 | | 27 | | 181 | | 69 |
| Sempra South American Utilities | | ― | | ― | | ― | | ― | | 33 | | 40 | | 33 | | 40 |
| Sempra Mexico | | ― | | ― | | 9 | | 3 | | 9 | | 9 | | 18 | | 12 |
| Sempra Renewables | | ― | | ― | | ― | | ― | | 2 | | 2 | | 2 | | 2 |
| Sempra Natural Gas | | 83 | | 68 | | 5 | | 5 | | 1 | | 5 | | 89 | | 78 |
| Sempra Energy Consolidated | $ | 246 | $ | 113 | $ | 14 | $ | 8 | $ | 136 | $ | 166 | $ | 396 | $ | 287 |
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. Later in 2013, we received $238 million in cash for the remaining grants receivable.
Income tax expense includes current and deferred income taxes from operations during the year. We record deferred income taxes for temporary differences between the book and the tax basis of assets and liabilities. Investment tax credits from prior years are amortized to income by the California Utilities over the estimated service lives of the properties as required by the CPUC. At our other businesses, we reduce the book basis of the related asset by the amount of investment tax credit earned. At Sempra Renewables, production tax credits are recognized in income tax expense as earned.
The California Utilities, Mobile Gas and Willmut Gas recognize
| § | regulatory assets to offset deferred tax liabilities if it is probable that the amounts will be recovered from customers; and |
| § | regulatory liabilities to offset deferred tax assets if it is probable that the amounts will be returned to customers. |
We currently do not record deferred income taxes for basis differences between financial statement and income tax investment amounts in non-U.S. subsidiaries and non-U.S. joint ventures because their cumulative undistributed earnings are indefinitely reinvested.
When there are uncertainties related to potential income tax benefits, in order to qualify for recognition, the position we take has to have at least a “more likely than not” chance of being sustained (based on the position’s technical merits) upon challenge by the respective authorities. The term “more likely than not” means a likelihood of more than 50 percent. Otherwise, we may not recognize any of the potential tax benefit associated with the position. We recognize a benefit for a tax position that meets the “more likely than not” criterion at the largest amount of tax benefit that is greater than 50 percent likely of being realized upon its effective resolution.
Unrecognized tax benefits involve management’s judgment regarding the likelihood of the benefit being sustained. The final resolution of uncertain tax positions could result in adjustments to recorded amounts and may affect our results of operations, financial position and cash flows.
We provide additional information about income taxes in Note 6.
GREENHOUSE GAS ALLOWANCES
The California Utilities, Sempra Mexico and Sempra Natural Gas are required by California Assembly Bill 32 to acquire greenhouse gas allowances for every metric ton of carbon dioxide equivalent emitted into the atmosphere during electric generation and natural gas transportation. We record greenhouse gas allowances at the lower of weighted average cost or market, and include them in Other Current Assets and Sundry on the Consolidated Balance Sheets based on the dates that they are required to be surrendered. We measure the compliance obligation, which is based on emissions, at the carrying value of allowances held plus the fair value of additional allowances necessary to satisfy the obligation. We include the obligation in Other Current Liabilities and Deferred Credits on the Consolidated Balance Sheets based on the dates that the allowances will be surrendered. We remove the assets and liabilities from the balance sheets as the allowances are surrendered.
The California Utilities expect that costs and revenues associated with the greenhouse gas program will be recorded through Regulatory Balancing Accounts on the Consolidated Balance Sheets.
RENEWABLE ENERGY CERTIFICATES
Renewable energy certificates (RECs) represent property rights established by governmental agencies for the environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying physical electricity associated with a renewable-based generation source in certain markets.
Retail sellers of electricity obtain RECs through renewable power purchase agreements, internal generation or separate purchases in the market to comply with renewable portfolio standards established by the governmental agencies. RECs are the mechanism used to verify renewable portfolio standards compliance. The cost of RECs is recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment primarily represents the buildings, equipment and other facilities used by the California Utilities to provide natural gas and electric utility services, and by Sempra International and Sempra U.S. Gas & Power, including construction work in progress at these operating units. Property, plant and equipment also includes lease improvements and other equipment at Parent, as well as property acquired under a build-to-suit lease included in construction work in progress.
Our plant costs include
| § | materials and contract services |
| § | expenditures for replacement parts incurred during a major maintenance outage of a generating plant |
In addition, the cost of our utility plant and selected non-utility regulated projects at Sempra Mexico and Sempra Natural Gas includes an allowance for funds used during construction (AFUDC). We discuss AFUDC below. The cost of non-utility plant includes capitalized interest.
Maintenance costs are expensed as incurred. The cost of most retired depreciable utility plant minus salvage value is charged to accumulated depreciation.
We discuss assets pledged as security for loans in Note 5.
| PROPERTY, PLANT AND EQUIPMENT BY MAJOR FUNCTIONAL CATEGORY |
| (Dollars in millions) |
| | | Property, plant | | Depreciation rates for |
| | | and equipment at | | years ended |
| | | December 31, | | December 31, |
| | | 2014 | 2013 | | 2014 | 2013 | 2012 |
| SDG&E: | | | | | | | | | | | |
| Natural gas operations | $ | 1,535 | $ | 1,454 | | 2.72 | % | 2.35 | % | 3.20 | % |
| Electric distribution | | 5,795 | | 5,492 | | 3.79 | | 3.36 | | 4.15 | |
| Electric transmission(1) | | 4,525 | | 3,932 | | 2.59 | | 2.58 | | 2.63 | |
| Electric generation(2) | | 1,862 | | 1,768 | | 3.86 | | 3.76 | | 4.68 | |
| Other electric(3) | | 851 | | 759 | | 7.09 | | 7.58 | | 7.92 | |
| Construction work in progress(1) | | 910 | | 941 | | NA | | NA | | NA | |
| Total SDG&E | | 15,478 | | 14,346 | | | | | | | |
| SoCalGas: | | | | | | | | | | | |
| Natural gas operations(4) | | 12,098 | | 11,394 | | 3.89 | | 3.70 | | 3.74 | |
| Other non-utility | | 120 | | 118 | | 2.88 | | 1.56 | | 1.36 | |
| Construction work in progress | | 668 | | 319 | | NA | | NA | | NA | |
| Total SoCalGas | | 12,886 | | 11,831 | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | Estimated | Weighted average |
Other operating units and parent(5): | | | | | | useful lives | useful life |
| Land and land rights | | 290 | | 276 | | 26 to 55 years(6) | 41 |
| Machinery and equipment: | | | | | | | | | | | |
| Utility electric distribution operations | | 1,434 | | 1,440 | | 10 to 46 years | 41 |
| Generating plants | | 596 | | 993 | | 30 to 50 years | 32 |
| LNG terminals | | 1,122 | | 2,094 | | 5 to 43 years | 43 |
| Pipelines and storage | | 2,003 | | 1,638 | | 3 to 55 years | 46 |
| Other | | 213 | | 212 | | 1 to 50 years | 13 |
| Construction work in progress | | 1,053 | | 1,283 | | NA | NA |
| Other | | 332 | | 294 | | 1 to 80 years | 27 |
| | | 7,043 | | 8,230 | | | | | | | |
| Total Sempra Energy Consolidated | $ | 35,407 | $ | 34,407 | | | | | | | |
| (1) | At December 31, 2014, includes $365 million in electric transmission assets and $12 million in construction work in progress related to SDG&E's 91-percent interest in the Southwest Powerlink (SWPL) transmission line, jointly owned by SDG&E with other utilities. 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 its share of the project and participates in decisions concerning operations and capital expenditures. |
| (2) | Includes capital lease assets of $243 million and $183 million at December 31, 2014 and 2013, respectively, primarily related to variable interest entities of which SDG&E is not the primary beneficiary. |
| (3) | Includes capital lease assets of $19 million and $23 million at December 31, 2014 and 2013, respectively. |
| (4) | Includes capital lease assets of $27 million and $33 million at December 31, 2014 and 2013, respectively. |
| (5) | December 31, 2014 balances include $150 million, $191 million and $24 million of utility plant, primarily pipelines and other distribution assets, at Ecogas, Mobile Gas and Willmut Gas, respectively. December 31, 2013 balances include $155 million, $180 million and $22 million of utility plant, primarily pipelines and other distribution assets, at Ecogas, Mobile Gas and Willmut Gas, respectively. |
| (6) | Estimated useful lives are for land rights. |
Depreciation expense is based on the straight-line method over the useful lives of the assets or, for the California Utilities, a shorter period prescribed by the CPUC. Depreciation expense is computed using the straight-line method over the asset’s estimated original composite useful life, the CPUC-prescribed period or the remaining term of the site leases, whichever is shortest. Depreciation expense for Sempra Energy for the years ended December 31, 2014, 2013 and 2012, was $1,146 million, $1,103 million and $1,080 million, respectively. Depreciation expense for SDG&E for the years ended December 31, 2014, 2013 and 2012, was $530 million, $494 million and $490 million, respectively. Depreciation expense for SoCalGas for the years ended December 31, 2014, 2013 and 2012, was $431 million, $383 million and $362 million, respectively.
Accumulated depreciation on our Consolidated Balance Sheets is as follows:
| ACCUMULATED DEPRECIATION |
| (Dollars in millions) |
| | | December 31, |
| | | 2014 | 2013 |
| SDG&E: | | | | |
| Accumulated depreciation: | | | | |
| Electric(1) | $ | 3,192 | $ | 2,861 |
| Natural gas | | 668 | | 639 |
| Total SDG&E | | 3,860 | | 3,500 |
| SoCalGas: | | | | |
| Accumulated depreciation of natural gas utility plant in service(2) | | 4,555 | | 4,279 |
| Accumulated depreciation – other non-utility | | 87 | | 85 |
| Total SoCalGas | | 4,642 | | 4,364 |
| Other operating units and parent: | | | | |
| Accumulated depreciation – other(3) | | 824 | | 938 |
| Accumulated depreciation of utility electric distribution operations | | 179 | | 145 |
| | | | 1,003 | | 1,083 |
| Total Sempra Energy Consolidated | $ | 9,505 | $ | 8,947 |
| (1) | Includes accumulated depreciation for assets under capital lease of $28 million and $26 million at December 31, 2014 and 2013, respectively. Includes $211 million at December 31, 2014 related to SDG&E's 91-percent interest in the SWPL transmission line, jointly owned by SDG&E and other utilities. |
| (2) | Includes accumulated depreciation for assets under capital lease of $27 million and $31 million at December 31, 2014 and 2013, respectively. |
| (3) | December 31, 2014 balances include $37 million, $29 million and $2 million of accumulated depreciation for utility plant at Ecogas, Mobile Gas and Willmut Gas, respectively. December 31, 2013 balances include $38 million, $25 million and $2 million of accumulated depreciation for utility plant at Ecogas, Mobile Gas and Willmut Gas, respectively. |
The California Utilities finance their construction projects with borrowed funds and equity funds. The CPUC and the FERC allow the recovery of the cost of these funds by the capitalization of AFUDC, calculated using rates authorized by the CPUC and the FERC, as a cost component of property, plant and equipment. The California Utilities earn a return on the capitalized AFUDC after the utility property is placed in service and recover the AFUDC from their customers over the expected useful lives of the assets.
Pipeline projects currently under construction by Sempra Mexico and Sempra Natural Gas that are both subject to certain regulation 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 equity for its Sonora Pipeline project, totaling $43 million and $19 million for the years ended December 31, 2014 and 2013, respectively.
Sempra International and Sempra U.S. Gas & Power businesses capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations. The California Utilities also capitalize certain interest costs.
| CAPITALIZED FINANCING COSTS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| AFUDC related to debt | $ | 22 | $ | 22 | $ | 38 |
| AFUDC related to equity | | 106 | | 75 | | 96 |
| Other capitalized financing costs | | 39 | | 22 | | 52 |
| Total Sempra Energy Consolidated | $ | 167 | $ | 119 | $ | 186 |
| SDG&E: | | | | | | |
| AFUDC related to debt | $ | 15 | $ | 16 | $ | 30 |
| AFUDC related to equity | | 37 | | 39 | | 71 |
| Total SDG&E | $ | 52 | $ | 55 | $ | 101 |
| SoCalGas: | | | | | | |
| AFUDC related to debt | $ | 7 | $ | 6 | $ | 8 |
| AFUDC related to equity | | 26 | | 17 | | 25 |
| Other capitalized financing costs | | 1 | | 1 | | 1 |
| Total SoCalGas | $ | 34 | $ | 24 | $ | 34 |
GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested for impairment annually on October 1 or whenever events or changes in circumstances necessitate an evaluation. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value. If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.
For our annual goodwill impairment testing, under current U.S. GAAP guidance we have the option to first make a qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step, quantitative goodwill impairment test. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors, changes in key personnel and the overall financial performance of the reporting unit. If, after assessing these qualitative factors, we determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then we perform the two-step goodwill impairment test. When we perform the two-step, quantitative goodwill impairment test, we exercise judgment to develop estimates of the fair value of the reporting unit and the corresponding goodwill. Our fair value estimates are developed from the perspective of a knowledgeable market participant. We consider observable transactions in the marketplace for similar investments, if available, as well as an income-based approach such as discounted cash flow analysis. A discounted cash flow analysis may be based directly on anticipated future revenues and expenses and may be performed based on free cash flows generated within the reporting unit. Critical assumptions that affect our estimates of fair value may include
| § | consideration of market transactions |
| § | the appropriate risk-adjusted discount rate |
Goodwill included on the Sempra Energy Consolidated Balance Sheets is as follows:
| GOODWILL | | | | | | | | |
| (Dollars in millions) | | | | | | | | |
| | | | Sempra | | | | | | |
| | | South American | Sempra | | Sempra | | |
| | | | Utilities | | Mexico | | Natural Gas | | Total |
| Balance at December 31, 2012 | $ | 1,014 | $ | 25 | $ | 72 | $ | 1,111 |
| Foreign currency translation(1) | | (87) | | ― | | ― | | (87) |
| Balance at December 31, 2013 | | 927 | | 25 | | 72 | | 1,024 |
| Foreign currency translation(1) | | (93) | | ― | | ― | | (93) |
| Balance at December 31, 2014 | $ | 834 | $ | 25 | $ | 72 | $ | 931 |
| (1) | We record the offset of this fluctuation to other comprehensive income. | | | |
We provide additional information concerning goodwill related to our equity method investments and the impairment of investments in unconsolidated subsidiaries in Note 4.
Other Intangible Assets primarily represent storage and development rights related to the natural gas storage facilities of Bay Gas Storage Company, Ltd. (Bay Gas) and Mississippi Hub, LLC (Mississippi Hub), which are being amortized over their estimated useful lives as shown in the table below.
Other Intangible Assets included on the Sempra Energy Consolidated Balance Sheets are as follows:
| OTHER INTANGIBLE ASSETS | | | | | |
| (Dollars in millions) | | | | | |
| | Amortization period | December 31, |
| | (years) | 2014 | 2013 |
| Storage rights | 46 | $ | 138 | $ | 138 |
| Development rights | 50 | | 322 | | 322 |
| Other | 10 years to indefinite | | 18 | | 19 |
| | | | 478 | | 479 |
| Less accumulated amortization: | | | | | |
| Storage rights | | | (19) | | (16) |
| Development rights | | | (40) | | (34) |
| Other | | | (4) | | (3) |
| | | | (63) | | (53) |
| | | $ | 415 | $ | 426 |
Amortization expense for such intangible assets was $10 million in each of 2014, 2013 and 2012. We estimate the amortization expense for the next five years to be $10 million per year.
We test long-lived assets for recoverability whenever events or changes in circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Long-lived assets include intangible assets subject to amortization, but do not include investments in unconsolidated subsidiaries. Events or changes in circumstances that indicate that the carrying amount of a long-lived asset may not be recoverable may include
| § | significant decreases in the market price of an asset |
| § | a significant adverse change in the extent or manner in which we use an asset or in its physical condition |
| § | a significant adverse change in legal or regulatory factors or in the business climate that could affect the value of an asset |
| § | a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection of continuing losses associated with the use of a long-lived asset |
| § | a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life |
Impairment of long-lived assets occurs when the estimated future undiscounted cash flows are less than the carrying amount of the assets. If that comparison indicates that the assets’ carrying value may not be recoverable, the impairment is measured based on the difference between the carrying amount and the fair value of the assets. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
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-megawatt (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. Accordingly, SDG&E and Sempra Energy have consolidated Otay Mesa VIE. Otay Mesa VIE’s equity of $60 million at December 31, 2014 and $91 million at December 31, 2013 is included on the Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.
OMEC LLC has a loan outstanding of $325 million at December 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 9.
Cameron LNG Holdings
Sempra Energy’s equity-method investment in Cameron LNG Holdings is considered to be a VIE generally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG Holdings. We will continue to evaluate Cameron LNG Holdings for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG holdings at December 31, 2014 was $1,007 million, as we discuss in Note 4. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed in Note 4.
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 December 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 Consolidated Financial Statements 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 tables below correspond to SDG&E’s Consolidated Balance Sheets and Consolidated Statements of Operations.
| AMOUNTS ASSOCIATED WITH OTAY MESA VIE |
| (Dollars in millions) |
| | | | December 31, |
| | | | 2014 | 2013 |
| Cash and cash equivalents | $ | 5 | $ | 17 |
| Restricted cash | | | | | | 8 | | 6 |
| Inventories | | 3 | | 2 |
| Other | | 1 | | 1 |
| Total current assets | | 17 | | 26 |
| Restricted cash | | | | | | 11 | | 25 |
| Sundry | | 3 | | 4 |
| Property, plant and equipment, net | | 410 | | 438 |
| Total assets | $ | 441 | $ | 493 |
| | | | | |
| Current portion of long-term debt | $ | 10 | $ | 10 |
| Fixed-price contracts and other derivatives | | 16 | | 16 |
| Other | | 3 | | 19 |
| Total current liabilities | | 29 | | 45 |
| Long-term debt | | 315 | | 325 |
| Fixed-price contracts and other derivatives | | 31 | | 39 |
| Deferred credits and other | | 6 | | (7) |
| Other noncontrolling interest | | 60 | | 91 |
| Total liabilities and equity | $ | 441 | $ | 493 |
| | | | | | | | | | |
| | | | | Years ended December 31, |
| | | | 2014 | 2013 | 2012 |
| Operating expenses | | | | | | |
| Cost of electric fuel and purchased power | $ | (83) | $ | (91) | $ | (83) |
| Operation and maintenance | 19 | | 24 | | 19 |
| Depreciation and amortization | | | | 27 | | 28 | | 26 |
| Total operating expenses | | | | (37) | | (39) | | (38) |
| Operating income | | | | 37 | | 39 | | 38 |
| Other expense, net | | | | ― | | ― | | (1) |
| Interest expense | | | | (17) | | (15) | | (11) |
| Income before income taxes/Net income | | 20 | | 24 | | 26 |
| Earnings attributable to noncontrolling interest | | (20) | | (24) | | (26) |
| Earnings | $ | ― | $ | ― | $ | ― |
ASSET RETIREMENT OBLIGATIONS
For tangible long-lived assets, we record asset retirement obligations for the present value of liabilities of future costs expected to be incurred when assets are retired from service, if the retirement process is legally required and if a reasonable estimate of fair value can be made. We also record a liability if a legal obligation to perform an asset retirement exists and can be reasonably estimated, but performance is conditional upon a future event. We record the estimated retirement cost over the life of the related asset by depreciating the present value of the obligation (measured at the time of the asset’s acquisition) and accreting the discount until the liability is settled. Rate-regulated entities, including the California Utilities, record regulatory assets or liabilities as a result of the timing difference between the recognition of costs in accordance with U.S. GAAP and costs recovered through the rate-making process.
We have recorded asset retirement obligations related to various assets, including:
SDG&E and SoCalGas
| § | natural gas distribution systems |
| § | hazardous waste storage facilities |
| § | asbestos-containing construction materials |
SDG&E
| § | decommissioning of nuclear power facilities |
| § | electric distribution and transmission systems |
| § | site restoration of a former power plant |
| § | power generation plant (natural gas) |
SoCalGas
| § | natural gas transmission pipelines |
| § | underground natural gas storage facilities and wells |
Sempra Mexico
| § | power generation plant (natural gas) |
| § | natural gas distribution and transportation systems |
Sempra Renewables
| § | certain power generation plants (solar) |
Sempra Natural Gas
| § | power generation plant (natural gas) |
| § | natural gas distribution and transportation systems |
| § | underground natural gas storage facilities |
The changes in asset retirement obligations are as follows:
| CHANGES IN ASSET RETIREMENT OBLIGATIONS |
| (Dollars in millions) |
| | | Sempra Energy | | | | | | |
| | | Consolidated | | SDG&E | | SoCalGas |
| | | 2014 | 2013 | | 2014 | 2013 | | 2014 | 2013 |
| Balance as of January 1(1) | $ | 2,152 | $ | 2,056 | | $ | 913 | $ | 741 | | $ | 1,199 | $ | 1,253 |
| Accretion expense | | 97 | | 97 | | | 43 | | 45 | | | 52 | | 49 |
| Liabilities incurred | | 4 | | 4 | | | ― | | ― | | | ― | | ― |
| Reclassification(2) | | (6) | | ― | | | ― | | ― | | | ― | | ― |
| Payments | | (29) | | (49) | | | (29) | | (48) | | | ― | | ― |
| Revisions, GRC-related(3) | | ― | | (135) | | | ― | | (30) | | | ― | | (105) |
| Revisions, other(4)(5) | | (28) | | 179 | | | (54) | | 205 | | | 25 | | 2 |
| Balance at December 31(1) | $ | 2,190 | $ | 2,152 | | $ | 873 | $ | 913 | | $ | 1,276 | $ | 1,199 |
| (1) | The current portions of the obligations are included in Other Current Liabilities on the Consolidated Balance Sheets. |
| (2) | Reclassification to liability held for sale - asset retirement obligation which is included in Other Current Liabilities on the Consolidated Balance Sheets, as we discuss in "Asset Held for Sale" in Note 3. |
| (3) | The decreases in asset retirement obligations in 2013 at SDG&E and SoCalGas are due to revised estimates related to the 2012 General Rate Case (GRC) that received final approval in May 2013. At SDG&E, these revisions included increases in asset service lives ranging from 2 percent to 7 percent, and lower estimated cost of removal. At SoCalGas, the decrease includes increases in asset service lives ranging from 4 percent to 6 percent, partially offset by a higher estimated cost of removal. |
| (4) | The decrease in asset retirement obligations in 2014 at SDG&E is due to revised estimates in an updated decommissioning cost study for the San Onofre Nuclear Generating Station, which we discuss in Note 13. The increase in asset retirement obligations in 2014 at SoCalGas is related to a change in estimates. |
| (5) | The increase in asset retirement obligations in 2013 at SDG&E is due to revised estimates recorded in the third quarter of 2013 related to the early decommissioning of SONGS Units 2 and 3 (see Note 13). |
CONTINGENCIES
We accrue losses for the estimated impacts of various conditions, situations or circumstances involving uncertain outcomes. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date and:
| § | information available through the date we file our financial statements indicates it is probable that a loss has been incurred, given the likelihood of uncertain future events; and |
| § | the amount of the loss can be reasonably estimated. |
We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events.
Legal fees that are associated with a past event for which a liability has been recorded are accrued when it is probable that fees also will be incurred.
Comprehensive income includes all changes in the equity of a business enterprise (except those resulting from investments by owners and distributions to owners), including:
| § | foreign currency translation adjustments |
| § | changes in unamortized net actuarial gain or loss and prior service cost related to pension and other postretirement benefits plans |
| § | unrealized gains or losses on available-for-sale securities |
| § | certain hedging activities |
The Consolidated Statements of Comprehensive Income show the changes in the components of other comprehensive income (loss) (OCI), including the amounts attributable to noncontrolling interests. 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, for the years ended December 31:
| CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1) |
| SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | | | Pension and other | | | | |
| | | | | postretirement benefits | | | | |
| | | Foreign | | | | | | Total |
| | | currency | Unamortized | Unamortized | | accumulated other |
| | | translation | net actuarial | prior service | Financial | comprehensive |
| | | adjustments | gain (loss) | credit (cost) | instruments | income (loss) |
| 2014: | | | | | | | | | | |
| Balance as of December 31, 2013 | $ | (129) | $ | (73) | $ | ― | $ | (26) | $ | (228) |
| Other comprehensive loss before | | | | | | | | | | |
| reclassifications | | (193) | | (24) | | (2) | | (70) | | (289) |
| Amounts reclassified from accumulated other | | | | | | | | | | |
| comprehensive income | | ― | | 14 | | ― | | 6 | | 20 |
| Net other comprehensive loss | | (193) | | (10) | | (2) | | (64) | | (269) |
| Balance as of December 31, 2014 | $ | (322) | $ | (83) | $ | (2) | $ | (90) | $ | (497) |
| 2013: | | | | | | | | | | |
| Balance as of December 31, 2012 | $ | (240) | $ | (102) | $ | 1 | $ | (35) | $ | (376) |
| Other comprehensive (loss) income before | | | | | | | | | | |
| reclassifications | | (159) | | 21 | | (1) | | 2 | | (137) |
| Amounts reclassified from accumulated other | | | | | | | | | | |
| comprehensive income | | 270 | (2) | 8 | | ― | | 7 | | 285 |
| Net other comprehensive income (loss) | | 111 | | 29 | | (1) | | 9 | | 148 |
| Balance as of December 31, 2013 | $ | (129) | $ | (73) | $ | ― | $ | (26) | $ | (228) |
| 2012: | | | | | | | | | | |
| Balance as of December 31, 2011 | $ | (359) | $ | (100) | $ | 1 | $ | (31) | $ | (489) |
| Other comprehensive income (loss) before | | | | | | | | | | |
| reclassifications | | 119 | | (13) | | ― | | (10) | | 96 |
| Amounts reclassified from accumulated other | | | | | | | | | | |
| comprehensive income | | ― | | 11 | | ― | | 6 | | 17 |
| Net other comprehensive income (loss) | | 119 | | (2) | | ― | | (4) | | 113 |
| Balance as of December 31, 2012 | $ | (240) | $ | (102) | $ | 1 | $ | (35) | $ | (376) |
| (1) | All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests. |
| (2) | Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4. |
| CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1) |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| (Dollars in millions) |
| | | Pension and other | | | |
| | | postretirement benefits | | | |
| | | | | | | Total |
| | | Unamortized | Unamortized | | accumulated other |
| | | net actuarial | prior service | | comprehensive |
| | | gain (loss) | credit | | income (loss) |
| 2014: | | | | | | | |
| Balance as of December 31, 2013 | $ | (10) | $ | 1 | | $ | (9) |
| Other comprehensive loss before | | | | | | | |
| reclassifications | | (5) | | ― | | | (5) |
| Amounts reclassified from accumulated other | | | | | | | |
| comprehensive income | | 2 | | ― | | | 2 |
| Net other comprehensive loss | | (3) | | ― | | | (3) |
| Balance as of December 31, 2014 | $ | (13) | $ | 1 | | $ | (12) |
| 2013: | | | | | | | |
| Balance as of December 31, 2012 | $ | (12) | $ | 1 | | $ | (11) |
| Amounts reclassified from accumulated other | | | | | | | |
| comprehensive income | | 2 | | ― | | | 2 |
| Net other comprehensive income | | 2 | | ― | | | 2 |
| Balance as of December 31, 2013 | $ | (10) | $ | 1 | | $ | (9) |
| 2012: | | | | | | | |
| Balance as of December 31, 2011 | $ | (11) | $ | 1 | | $ | (10) |
| Other comprehensive loss before | | | | | | | |
| reclassifications | | (2) | | ― | | | (2) |
| Amounts reclassified from accumulated other | | | | | | | |
| comprehensive loss | | 1 | | ― | | | 1 |
| Net other comprehensive loss | | (1) | | ― | | | (1) |
| Balance as of December 31, 2012 | $ | (12) | $ | 1 | | $ | (11) |
| (1) | All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests. |
| CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1) |
| SOUTHERN CALIFORNIA GAS COMPANY |
| (Dollars in millions) |
| | | Pension and other | | | | |
| | | postretirement benefits | | | | |
| | | | | | | | Total |
| | | Unamortized | Unamortized | | accumulated other |
| | | net actuarial | prior service | Financial | comprehensive |
| | | gain (loss) | credit | instruments | income (loss) |
| 2014: | | | | | | | | |
| Balance as of December 31, 2013 | $ | (5) | $ | 1 | $ | (14) | $ | (18) |
| Other comprehensive loss before | | | | | | | | |
| reclassifications | | (3) | | ― | | ― | | (3) |
| Amounts reclassified from accumulated other | | | | | | | | |
| comprehensive income | | 3 | | ― | | ― | | 3 |
| Net other comprehensive income | | ― | | ― | | ― | | ― |
| Balance as of December 31, 2014 | $ | (5) | $ | 1 | $ | (14) | $ | (18) |
| 2013: | | | | | | | | |
| Balance as of December 31, 2012 | $ | (4) | $ | 1 | $ | (15) | $ | (18) |
| Other comprehensive loss before | | | | | | | | |
| reclassifications | | (2) | | ― | | ― | | (2) |
| Amounts reclassified from accumulated other | | | | | | | | |
| comprehensive income | | 1 | | ― | | 1 | | 2 |
| Net other comprehensive (loss) income | | (1) | | ― | | 1 | | ― |
| Balance as of December 31, 2013 | $ | (5) | $ | 1 | $ | (14) | $ | (18) |
| 2012: | | | | | | | | |
| Balance as of December 31, 2011 | $ | (6) | $ | 1 | $ | (16) | $ | (21) |
| Other comprehensive income before | | | | | | | | |
| reclassifications | | 1 | | ― | | ― | | 1 |
| Amounts reclassified from accumulated other | | | | | | | | |
| comprehensive income | | 1 | | ― | | 1 | | 2 |
| Net other comprehensive income | | 2 | | ― | | 1 | | 3 |
| Balance as of December 31, 2012 | $ | (4) | $ | 1 | $ | (15) | $ | (18) |
| (1) | All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests. |
| RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) |
| (Dollars in millions) |
| | Amounts reclassified | | |
| Details about accumulated | from accumulated other | | Affected line item |
| other comprehensive income (loss) components | comprehensive income (loss) | | on consolidated statement of operations |
| | | | Years ended December 31, | | | | | |
| | | | 2014 | 2013 | 2012 | | | | | |
| Sempra Energy Consolidated: | | | | | | | | | | | |
| Foreign currency translation adjustments | $ | ― | $ | 270 | $ | ― | | Equity Earnings, Net of Income Tax(1) |
| | | | | | | | | | | | | | |
| Financial instruments: | | | | | | | | | | | |
| Interest rate and foreign exchange instruments | $ | 21 | $ | 11 | $ | 9 | | Interest Expense |
| Interest rate instruments | | (3) | | ― | | ― | | Gain on Sale of Equity Interests and Assets |
| Interest rate instruments | | 10 | | 10 | | 6 | | Equity Earnings, Before Income Tax |
| Commodity contracts not subject to | | | | | | | | Revenues: Energy-Related |
| | rate recovery | | (8) | | (1) | | ― | | Businesses |
| Total before income tax | | 20 | | 20 | | 15 | | |
| | | | | (3) | | (4) | | (4) | | Income Tax Expense |
| Net of income tax | | 17 | | 16 | | 11 | | |
| | | | | (11) | | (9) | | (5) | | Earnings Attributable to Noncontrolling Interests |
| | | | $ | 6 | $ | 7 | $ | 6 | | | | | |
| | | | | | | | | | | | | | |
| Pension and other postretirement benefits: | | | | | | | | | | | |
| Net actuarial gain | $ | ― | $ | 3 | $ | 10 | | (2) |
| Amortization of actuarial loss | | 23 | | 10 | | 9 | | (2) |
| | | | | (9) | | (5) | | (8) | | Income Tax Expense |
| Net of income tax | $ | 14 | $ | 8 | $ | 11 | | |
| | | | | | | | | | | | | | |
| Total reclassifications for the period, net of tax | $ | 20 | $ | 285 | | 17 | | | | | |
| SDG&E: | | | | | | | | | | | |
| Financial instruments: | | | | | | | | | | | |
| Interest rate instruments | $ | 11 | $ | 9 | $ | 5 | | Interest Expense |
| | | | | (11) | | (9) | | (5) | | Earnings Attributable to Noncontrolling Interest |
| | | | $ | ― | $ | ― | $ | ― | | | | | |
| | | | | | | | | | | | | | |
| Pension and other postretirement benefits: | | | | | | | | | | | |
| Net actuarial gain | $ | ― | $ | 2 | $ | 1 | | (2) |
| Amortization of actuarial loss | | 3 | | 1 | | 1 | | (2) |
| | | | | (1) | | (1) | | (1) | | Income Tax Expense |
| Net of income tax | $ | 2 | $ | 2 | $ | 1 | | |
| | | | | | | | | | | | | | |
| Total reclassifications for the period, net of tax | $ | 2 | $ | 2 | $ | 1 | | | | | |
| SoCalGas: | | | | | | | | | | | |
| Financial instruments: | | | | | | | | | | | |
| Interest rate instruments | $ | 1 | $ | 1 | $ | 2 | | Interest Expense |
| | | | | (1) | | ― | | (1) | | Income Tax Expense |
| Net of income tax | $ | ― | $ | 1 | $ | 1 | | | | | |
| | | | | | | | | | | | | | |
| Pension and other postretirement benefits: | | | | | | | | | | | |
| Net actuarial gain | $ | ― | $ | ― | $ | 1 | | (2) |
| Amortization of actuarial loss | | 5 | | 1 | | 1 | | (2) |
| | | | | (2) | | ― | | (1) | | Income Tax Expense |
| Net of income tax | $ | 3 | $ | 1 | $ | 1 | | | | | |
| | | | | | | | | | | | | | |
| Total reclassifications for the period, net of tax | $ | 3 | $ | 2 | $ | 2 | | | | | |
| (1) | Represents cumulative foreign currency translation adjustment related to the impairment of our Argentine investments in 2006, which is substantially offset by an accrued liability established at that time. We provide additional information about these investments in Note 4. |
| (2) | Amounts are included in the computation of net periodic benefit cost (see "Net Periodic Benefit Cost, 2012 - 2014" in Note 7). |
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 Consolidated Balance Sheets. Earnings/losses attributable to the noncontrolling interests are separately identified on the Consolidated Statements of Operations, and net income/loss and comprehensive income/loss attributable to the noncontrolling interests are separately identified on the Consolidated Statements of Comprehensive Income and Consolidated Statements of Changes in Equity.
Sale of Noncontrolling Interests
In the first quarter of 2013, Sempra Energy’s 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. dollar equivalent. IEnova has used the net proceeds of the offerings primarily for general corporate purposes, and for the funding of its 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, 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, 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.
The private offering was exempt from registration under the U.S. Securities Act of 1933, as amended (the Securities Act), and shares in the private offering were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside of the United States, in accordance with Regulation S under the Securities Act. The shares were not registered under the Securities Act or any state securities laws, and may not be offered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act and applicable securities laws.
Purchase of Noncontrolling Interests
On December 10, 2014, we purchased 18,625,594 Luz del Sur shares for $74 million, increasing Sempra South American Utilities’ ownership from 79.8 percent to 83.6 percent.
Chilquinta Energía owned 85 percent of Luzlinares S.A. (Luzlinares) through October 31, 2012. On November 26, 2012, Chilquinta Energía purchased the remaining 15-percent ownership interest in Luzlinares for $7 million in cash.
The preferred stock at SoCalGas is presented at Sempra Energy as a noncontrolling interest at December 31, 2014 and 2013. The preferred stock of SDG&E at December 31, 2012 was contingently redeemable preferred stock and was fully redeemed in October 2013, as we discuss in Note 11. At Sempra Energy, the preferred stock dividends of SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 11.
Other Noncontrolling Interests
At December 31, 2014 and 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 Consolidated Balance Sheets:
| OTHER NONCONTROLLING INTERESTS | | |
| (Dollars in millions) | | |
| | | Percent ownership held by others | | December 31, |
| | | 2014 | | 2013 | | 2014 | 2013 |
| SDG&E: | | | | | | | | |
| Otay Mesa VIE | 100 | % | 100 | % | $ | 60 | $ | 91 |
| Sempra South American Utilities: | | | | | | | | |
| Chilquinta Energía subsidiaries(1) | 23.6 - 43.4 | | 24.4 - 43.4 | | | 23 | | 27 |
| Luz del Sur | 16.4 | | 20.2 | | | 177 | | 222 |
| Tecsur | 9.8 | | 9.8 | | | 4 | | 3 |
| Sempra Mexico: | | | | | | | | |
| IEnova, S.A.B. de C.V. | 18.9 | | 18.9 | | | 452 | | 442 |
| Sempra Natural Gas: | | | | | | | | |
| Bay Gas Storage Company, Ltd. | 9.1 | | 9.1 | | | 23 | | 22 |
| Liberty Gas Storage, LLC | 25.0 | | 25.0 | | | 14 | | 14 |
| Southern Gas Transmission Company | 49.0 | | 49.0 | | | 1 | | 1 |
| Total Sempra Energy | | | | | $ | 754 | $ | 822 |
| (1) | Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries. |
Our California Utilities generate revenues primarily from deliveries to their customers of electricity by SDG&E and natural gas by both SoCalGas and SDG&E and from related services. They record these revenues following the accrual method and recognize them upon delivery and performance. They also record revenue from CPUC-approved incentive awards, some of which require approval by the CPUC prior to being recognized. We provide additional discussion on utility incentive mechanisms in Note 14.
On a monthly basis, SoCalGas accrues natural gas storage contract revenues, which consist of storage reservation and variable charges based on negotiated agreements with terms of up to 15 years.
Our natural gas utilities outside of California (Mobile Gas, Willmut Gas and Ecogas) apply U.S. GAAP for regulated utilities consistent with the California Utilities.
Our electric distribution utilities in South America, Chilquinta Energía and Luz del Sur, serve primarily regulated customers, and their revenues are based on tariffs that are set by the National Energy Commission (Comisión Nacional de Energía, or CNE) in Chile and the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería, or OSINERGMIN) of the National Electricity Office under the Ministry of Energy and Mines in Peru.
The tariffs charged are based on an efficient model distribution company defined by Chilean law in the case of Chilquinta Energía, and OSINERGMIN in the case of Luz del Sur. The tariffs include operation and maintenance costs, an internal rate of return on the new replacement value of depreciable assets, charges for the use of transmission systems, and a component for the value added by the distributor. Tariffs are designed to provide for a pass-through to customers of the main noncontrollable cost items (mainly power purchases and transmission charges), recovery of reasonable operating and administrative costs, incentives to reduce costs and make needed capital investments and a regulated rate of return on the distributor’s regulated asset base. Because the tariffs are based on a model and are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in full cost recovery, they do not meet the requirement necessary for treatment under applicable U.S. GAAP for regulatory accounting.
For Chilquinta Energía, 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. The next review process for distribution rates is scheduled to be completed, with tariff adjustments also going into effect, in November 2016.
In April 2013, the CNE completed the process to establish Chilquinta Energía’s sub-transmission rates for the period January 2011 to December 2014, with tariff adjustments going into effect retroactively from January 2011. The sub-transmission rates period has been extended for one year, for one time only, to December 2015 due to a change in law issued in December 2014. Accordingly, the next review process for sub-transmission rates will be in January 2016, covering the period from January 2016 to December 2019.
The components of tariffs above for Luz del Sur are reviewed and adjusted every four years. The final distribution rate-setting resolution for the 2013-2017 period was published in October 2013 and went into effect on November 1, 2013.
The table below shows the total utilities revenues in Sempra Energy’s Consolidated Statements of Operations for each of the last three years. The revenues include amounts for services rendered but unbilled (approximately one-half month’s deliveries) at the end of each year.
| TOTAL UTILITIES REVENUES AT SEMPRA ENERGY CONSOLIDATED(1) |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Electric revenues | $ | 5,209 | $ | 4,911 | $ | 4,568 |
| Natural gas revenues | | 4,549 | | 4,398 | | 3,873 |
| Total | $ | 9,758 | $ | 9,309 | $ | 8,441 |
| (1) | Excludes intercompany revenues. | | | | | | |
As we discuss in Note 14, the natural gas supply for SDG&E’s and SoCalGas’ core natural gas customers is purchased by SoCalGas as a combined procurement portfolio managed by SoCalGas. Core customers are primarily residential and small commercial and industrial customers. This core gas procurement function is considered a shared service, therefore amounts related to SDG&E are not included in SoCalGas’ Consolidated Statements of Operations.
We provide additional information concerning utility revenue recognition in “Regulatory Matters” above.
Energy-Related Businesses
Sempra South American Utilities
Sempra South American Utilities generates revenues from energy-services companies that provide electric construction services and recognizes these revenues when services are provided in accordance with contractual agreements. The energy-services company in Chile also generates revenue from selling electricity to non-regulated customers.
Sempra Mexico
Sempra Mexico’s Termoeléctrica de Mexicali natural gas-fired power plant generates revenues from selling electricity and/or capacity to the California Independent System Operator (ISO) and to governmental, public utility and wholesale power marketing entities. Sempra Mexico recognizes these revenues as the electricity is delivered and capacity is provided. Sempra Mexico’s pipeline operations recognize revenues from the sale and transportation of natural gas as deliveries are made and from fixed capacity payments. Sempra Mexico also recognizes revenues from (1) the sale of LNG and natural gas as deliveries are made to counterparties and (2) from reservation and usage fees under terminal capacity agreements, nitrogen injection service agreements and tug service agreements. It reports revenue net of value added taxes in Mexico. Sempra Mexico’s revenues also include net realized gains and losses and the net change in the fair value of unrealized gains and losses on derivative contracts for natural gas.
Sempra Renewables
For consolidated entities, Sempra Renewables generates revenues from the sale of solar power pursuant to power purchase agreements, and recognizes these revenues when the power is delivered. It also generates revenues for the management of certain of its solar and wind project joint ventures.
Sempra Natural Gas
Sempra Natural Gas generates revenues from selling electricity and/or capacity from its Mesquite Power facility to the California ISO and to governmental, public utility and wholesale power marketing entities. Sempra Natural Gas recognizes these revenues as the electricity is delivered and capacity is provided. Related to its LNG terminal, prior to October 1, 2014, the effective date of the Cameron LNG Holdings joint venture, Sempra Natural Gas recognized revenues from reservation and usage fees. We discuss the deconsolidation of Cameron LNG, LLC and related assets further in Note 3. Sempra Natural Gas also records revenues from contractual counterparty obligations for non-delivery of LNG cargoes, as well as revenues from the sale of LNG and natural gas as deliveries are made to counterparties. Sempra Natural Gas recognizes revenue on natural gas storage and transportation operations when services are provided in accordance with contractual agreements for the storage and transportation services. Sempra Natural Gas revenues also include net realized gains and losses and the net change in the fair value of unrealized gains and losses on derivative contracts for power and natural gas.
Other Cost of Sales primarily includes
| § | pipeline capacity costs, and pipeline transportation and natural gas marketing costs incurred at Sempra Natural Gas; |
| § | electric construction services costs incurred by Sempra South American Utilities’ energy-services companies; and |
| § | energy management service fees at Sempra Mexico. |
OPERATION AND MAINTENANCE EXPENSES
Operation and Maintenance includes operating and maintenance costs, and general and administrative costs, consisting primarily of personnel costs, purchased materials and services, litigation expense and rent.
FOREIGN CURRENCY TRANSLATION
Our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assets and liabilities of their foreign operations are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the year. The resulting noncash translation adjustments do not enter into the calculation of earnings or retained earnings (unless the operation is being discontinued), but are reflected in Comprehensive Income and in Accumulated Other Comprehensive Income (Loss), a component of shareholders’ equity.
Currency transaction (losses) gains in a currency other than the entity’s functional currency were $(15) million, $(3) million, and $9 million for the years ended December 31, 2014, 2013, and 2012, respectively, and are included in Other Income, Net, at Sempra Energy.
Cash flows of the consolidated foreign subsidiaries are translated into U.S. dollars using average exchange rates for the period. We report the effect of exchange rate changes on cash balances held in foreign currencies in “Effect of Exchange Rate Changes on Cash and Cash Equivalents” on our Consolidated Statements of Cash Flows.
TRANSACTIONS WITH AFFILIATES
Due to and from Unconsolidated Affiliates – Sempra Energy Consolidated
Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A. to provide project financing for the construction of transmission lines. Eletrans S.A. is an affiliate of Chilquinta Energía that we discuss in Note 4. At December 31, 2014 and 2013, the principal balance outstanding was $40 million and $14 million, plus $1 million and a negligible amount of accumulated interest outstanding, respectively, at a fixed interest rate of 4 percent.
In the second half of 2014, Sempra Mexico made three four-year and one three-year, U.S. dollar-denominated loans to affiliates of Sempra Mexico’s joint venture with Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) to finance the Los Ramones Norte pipeline project. At December 31, 2014, these loans have principal balances outstanding aggregating $79 million and $44 million, respectively, plus $2 million of accumulated interest. These loans accrue interest at a variable rate based on a 30-day LIBOR plus 450 basis points (4.66 percent at December 31, 2014).
As we discuss in Note 3, in July 2014, Sempra Mexico sold a 50-percent interest in the first phase of the Energía Sierra Juárez wind project. Upon deconsolidation, the newly formed joint venture repaid a portion, in the amount of $18 million, of a previous intercompany loan from Sempra Mexico to Energía Sierra Juárez. The joint venture assumed the obligation to Sempra Mexico for the remainder of the loan, which has a principal balance outstanding at December 31, 2014 of $21 million plus $1 million of accumulated interest. This loan accrues interest at a variable rate based on a 30-day LIBOR plus 637.5 basis points (6.53 percent at December 31, 2014).
At December 31, 2014 and 2013, Sempra Energy had $38 million and $4 million, respectively, in accounts receivable from various Sempra Renewables and Sempra Mexico joint venture investments. Sempra Energy also had a $2 million contribution payable to Sempra Energy Foundation at December 31, 2014, which was paid in January 2015.
Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Also, from time to time, SDG&E and SoCalGas may loan surplus cash to Sempra Energy at interest rates based on one-month commercial paper rates. Amounts due to/from affiliates are as follows:
| AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS |
| (Dollars in millions) |
| | | December 31, |
| | 2014 | 2013 |
| SDG&E: | | | | |
| Current: | | | | |
| Due from various affiliates | $ | 1 | $ | 1 |
| | | | | |
| Due to Sempra Energy | $ | 17 | $ | 25 |
| Due to SoCalGas | | 4 | | ― |
| Due to various affiliates | | ― | | 14 |
| | | $ | 21 | $ | 39 |
| | | | | |
| Income taxes due from Sempra Energy(1) | $ | 16 | $ | 70 |
| SoCalGas: | | | | |
| Current: | | | | |
| Due from SDG&E | $ | 4 | $ | ― |
| Due from various affiliates | | ― | | 21 |
| | | $ | 4 | $ | 21 |
| | | | | | |
| Due to Sempra Energy | $ | 13 | $ | 16 |
| | | | | | |
| Income taxes due from Sempra Energy(1) | $ | 9 | $ | 18 |
| (1) | SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from the companies having always filed a separate return. |
Revenues from unconsolidated affiliates at SDG&E and SoCalGas are as follows:
| REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| SDG&E | $ | 13 | $ | 12 | $ | 9 |
| SoCalGas | | 69 | | 70 | | 46 |
Transactions with Rockies Express Pipelines LLC
Sempra Natural Gas has an agreement with Rockies Express Pipelines LLC (Rockies Express) for capacity on the Rockies Express pipeline (REX) through November 2019. Sempra Natural Gas recorded cost of sales of $78 million in each of 2014, 2013 and 2012 related to this agreement. We discuss this agreement further in Note 15.
Sempra Energy Consolidated
As we discuss below, the California Utilities have restrictions on the amount of funds that can be transferred to Sempra Energy by dividend, advance or loan as a result of conditions imposed by various regulators. Additionally, certain other Sempra Energy subsidiaries are subject to various financial and other covenants and other restrictions contained in debt and credit agreements (described in Note 5) and in other agreements that limit the amount of funds that can be transferred to Sempra Energy. At December 31, 2014, Sempra Energy was in compliance with all covenants related to its debt agreements.
At December 31, 2014, the amount of restricted net assets of wholly owned subsidiaries of Sempra Energy, including the California Utilities discussed below, that may not be distributed to Sempra Energy in the form of a loan or dividend is $6.6 billion. Additionally, the amount of restricted net assets of our unconsolidated entities is $2.1 billion. Although the restrictions cap the amount of funding that the various operating subsidiaries can provide to Sempra Energy, we do not believe these restrictions will have a significant impact on our ability to access cash to pay dividends.
As we discuss in Note 4, $187 million of Sempra Energy’s consolidated retained earnings balance represents undistributed earnings of equity method investments at December 31, 2014.
California Utilities
The CPUC’s regulation of the California Utilities’ capital structures limits the amounts available for dividends and loans to Sempra Energy. At December 31, 2014, Sempra Energy could have received combined loans and dividends of approximately $640 million from SDG&E and approximately $755 million from SoCalGas.
The payment and amount of future dividends by SDG&E and SoCalGas are at the discretion of their respective boards of directors. The following restrictions limit the amount of retained earnings that may be paid as common stock dividends or loaned to Sempra Energy from either utility:
| § | The CPUC requires that SDG&E’s and SoCalGas’ common equity ratios be no lower than one percentage point below the CPUC-authorized percentage of each entity’s authorized capital structure. The authorized percentage at December 31, 2014 is 52 percent at both SDG&E and SoCalGas. |
| § | The FERC requires SDG&E to maintain a common equity ratio of 30 percent or above. |
| § | The California Utilities have a combined revolving credit line that requires each utility to maintain a ratio of consolidated indebtedness to consolidated capitalization (as defined in the agreement) of no more than 65 percent, as we discuss in Note 5. |
Based on these restrictions, at December 31, 2014, SDG&E’s restricted net assets were $4.3 billion and SoCalGas’ restricted net assets were $2.0 billion, which could not be transferred to Sempra Energy.
Sempra International
Significant restrictions of Sempra International subsidiaries include
| § | Peru and Mexico require domestic corporations to maintain minimum legal reserves as a percentage of capital stock, resulting in restricted net assets of $35 million at Luz del Sur and $81 million at Sempra Energy’s consolidated Mexican subsidiaries at December 31, 2014. |
| § | Energía Sierra Juárez, a 50-percent owned and unconsolidated joint venture of Sempra Mexico (see Notes 3 and 4), has a long-term debt agreement that requires the establishment and funding of project and reserve accounts to which the proceeds of loans, letter of credit draws, project revenues and other amounts are deposited and applied in accordance with the debt agreement. The long-term debt agreement also limits the joint venture’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions. Also, in connection with a debt agreement for the financing of Mexican value added tax, Energía Sierra Juárez had $0.8 million of restricted net assets at December 31, 2014. |
| § | Gasoductos de Chihuahua, Sempra Mexico’s joint venture with PEMEX (see Note 4), has a debt agreement that requires the joint venture to maintain a reserve account to pay the debt. Under these restrictions, net assets totaling $32 million are restricted at December 31, 2014. |
Sempra U.S. Gas & Power
Significant restrictions of Sempra U.S. Gas & Power subsidiaries include
| § | Wholly owned Copper Mountain Solar 1 has a long-term debt agreement that requires the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreement. This long-term debt agreement also limits Copper Mountain Solar 1’s ability to incur liens, incur additional indebtedness, make acquisitions and undertake certain actions, while also requiring maintenance of certain debt ratios. Under these restrictions, net assets totaling $9 million are restricted at December 31, 2014. |
| § | 50-percent owned and unconsolidated joint ventures at Sempra Renewables have debt agreements that require each joint venture to maintain reserve accounts in order to pay the projects’ debt service and operation and maintenance requirements. We discuss Sempra Energy guarantees associated with these requirements in Note 5. At December 31, 2014, as a result of these requirements, there were total restricted net assets at our joint ventures of approximately: |
| □ | $10 million at Broken Bow 2 Wind |
| □ | $30 million at California solar partnership |
| □ | $26 million at Cedar Creek 2 Wind (Cedar Creek 2) |
| □ | $9 million at Copper Mountain Solar 2 |
| □ | $3 million at Copper Mountain Solar 3 |
| □ | $52 million at Flat Ridge 2 Wind (Flat Ridge 2) |
| □ | $35 million at Fowler Ridge 2 Wind (Fowler Ridge 2) |
| □ | $16 million at Mehoopany Wind (Mehoopany Wind) |
| □ | $94 million at Mesquite Solar 1 |
| § | Wholly owned Mobile Gas has long-term debt instruments containing restrictions relating to the payment of dividends and other distributions with respect to capital stock. Under these restrictions, net assets of approximately $116 million are restricted at December 31, 2014. |
| § | 91-percent owned Bay Gas has long-term debt instruments containing restrictions relating to the payment of dividends and other distributions if Bay Gas does not maintain a specified debt service coverage ratio. Bay Gas had no restricted net assets at December 31, 2014. |
| § | Sempra Natural Gas has an equity method investment in the Cameron LNG Holdings joint venture, which has debt agreements that require the establishment and funding of project accounts to which the proceeds of loans, project revenues and other amounts are deposited and applied in accordance with the debt agreements. The debt agreements require the joint venture to maintain reserve accounts in order to pay the project debt service, and also contain restrictions related to the payment of dividends and other distributions to the members of the joint venture. We discuss Sempra Energy guarantees associated with Cameron LNG Holdings’ debt agreements in Note 4. Under these restrictions, net assets of Cameron LNG Holdings of approximately $1.8 billion are restricted at December 31, 2014. |
Other Income, Net on the Consolidated Statements of Operations consists of the following:
| OTHER INCOME, NET |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| Allowance for equity funds used during construction | $ | 106 | $ | 75 | $ | 96 |
| Investment gains(1) | | 27 | | 39 | | 41 |
| Electrical infrastructure relocation income(2) | | 21 | | 4 | | 6 |
| (Losses) gains on interest rate and foreign exchange instruments, net | | (15) | | 17 | | 10 |
| Foreign currency (losses) gains | | (15) | | (3) | | 9 |
| Regulatory interest, net(3) | | 6 | | 5 | | 1 |
| Sundry, net | | 7 | | 3 | | 9 |
| | Total | $ | 137 | $ | 140 | $ | 172 |
| SDG&E: | | | | | | |
| Allowance for equity funds used during construction | $ | 37 | $ | 39 | $ | 71 |
| Regulatory interest, net(3) | | 6 | | 4 | | 2 |
| Sundry, net | | (3) | | (3) | | (4) |
| | Total | $ | 40 | $ | 40 | $ | 69 |
| SoCalGas: | | | | | | |
| Allowance for equity funds used during construction | $ | 26 | $ | 17 | $ | 25 |
| Regulatory interest, net(3) | | ― | | 1 | | (1) |
| Sundry, net | | (6) | | (7) | | (7) |
| | Total | $ | 20 | $ | 11 | $ | 17 |
| (1) | Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans. |
| (2) | Income at Luz del Sur associated with the relocation of electrical infrastructure. |
| (3) | Interest on regulatory balancing accounts. |
NOTE 2. NEW ACCOUNTING STANDARDS
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.
ASU 2014-09, “Revenue from Contracts with Customers” (ASU 2014-09): ASU 2014-09 provides accounting guidance for revenue arising from contracts with customers and affects all entities that enter into contracts to provide goods or services to their customers. The guidance also provides a model for the measurement and recognition of gains and losses on the sale of certain nonfinancial assets, such as property and equipment, including real estate. This guidance must be adopted using either a full retrospective approach for all periods presented in the period of adoption or a modified retrospective approach.
We will adopt ASU 2014-09 on January 1, 2017 as required. We have not yet selected a transition method nor have we determined the effect of the standard on our ongoing financial reporting.
NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY
We consolidate assets and liabilities acquired as of the purchase date and include earnings from acquisitions in consolidated earnings after the purchase date.
During the years ended December 31, 2014 and 2013, Sempra Energy completed the sale of equity interests in various subsidiaries that were previously wholly owned as well as the contribution of Cameron LNG, LLC to a joint venture in exchange for an equity interest in the joint venture. The following table summarizes the deconsolidation of those subsidiaries, and we discuss each transaction below, along with other acquisition and divestiture activity, by segment.
| DECONSOLIDATION OF SUBSIDIARIES |
| (Dollars in millions) | |
| | | Broken Bow 2 Wind | Cameron LNG | Energía Sierra Juárez | Copper Mountain Solar 3 | Sempra Energy Consolidated |
| | | At November 5 | At October 1 | At July 16 | At March 13 | |
| 2014: | | | | | | | | |
| Proceeds, net of negligible transaction costs | $ | 58 | $ | ― | $ | 26 | $ | 68 | $ | 152 |
| Cash | | ― | | (6) | | (2) | | (2) | | (10) |
| Restricted cash | | (5) | | ― | | ― | | ― | | (5) |
| Other current assets | | (1) | | (11) | | (11) | | ― | | (23) |
| Property, plant and equipment, net | | (151) | | (1,022) | | (137) | | (247) | | (1,557) |
| Other assets | | (8) | | (30) | | (16) | | (11) | | (65) |
| Accounts payable and accrued expenses | | 3 | | 93 | | 10 | | 82 | | 188 |
| Due to affiliate | | ― | | ― | | 39 | | ― | | 39 |
| Long-term debt, including current portion | | 72 | | ― | | 82 | | 97 | | 251 |
| Other liabilities | | 2 | | ― | | 7 | | 3 | | 12 |
| Accumulated other comprehensive income | | ― | | ― | | (5) | | (2) | | (7) |
| Gain on sale of equity interests(1) | | (14) | | ― | | (19) | | (27) | | (60) |
| (Increase) in equity method investments upon | | | | | | | | | | |
| deconsolidation | $ | (44) | $ | (976) | $ | (26) | $ | (39) | $ | (1,085) |
| | | | | | | | | | | | |
| | | | | Mesquite Solar 1 | Copper Mountain Solar 2 | Sempra Energy Consolidated |
| | | | | At September 19 | At July 11(3) | | |
| 2013: | | | | | | |
| Proceeds from sale, net of transaction costs(2) | | | | | $ | 100 | $ | 69 | $ | 169 |
| Property, plant and equipment, net | | | | | | (461) | | (266) | | (727) |
| Other assets | | | | | | (72) | | (30) | | (102) |
| Long-term debt, including current portion | | | | | | 297 | | 146 | | 443 |
| Other liabilities | | | | | | 31 | | 19 | | 50 |
| Gain on sale of equity interests(1) | | | | | | (36) | | (4) | | (40) |
| (Increase) in equity method investments upon | | | | | | | | | | |
| deconsolidation | | | | | $ | (141) | $ | (66) | $ | (207) |
| (1) | Included in Gain on Sale of Equity Interests and Assets on our Consolidated Statements of Operations. |
| (2) | Transaction costs were $3 million at both Mesquite Solar 1 and Copper Mountain Solar 2. |
| (3) | Proceeds from sale, net of transaction costs, was adjusted for financial position at closing in the fourth quarter of 2013. |
In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax). The gain on sale included a $7 million after-tax gain attributable to the remeasurement of the retained investment to fair value. Our remaining 50-percent interest in Energía Sierra Juárez is accounted for under the equity method.
In July 2013, Sempra Renewables formed a joint venture with Consolidated Edison Development (ConEdison Development), a nonrelated party, by selling a 50-percent interest in its 150-MW Copper Mountain Solar 2 solar power facility for $72 million in cash. Sempra Renewables recognized a pretax gain on the sale of $4 million ($2 million after-tax).
In September 2013, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in its 150-MW Mesquite Solar 1 solar power facility for $103 million in cash. Sempra Renewables recognized a pretax gain on the sale of $36 million ($22 million after-tax).
In March 2014, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in its 250-MW Copper Mountain Solar 3 solar power facility for $66 million in cash, net of $2 million cash sold. Sempra Renewables recognized a pretax gain on the sale of $27 million ($16 million after-tax).
In May 2014, Sempra Renewables invested $121 million (as adjusted for financial position at closing) to become a 50-percent partner with ConEdison Development in four solar projects in California. We discuss our investment in the California solar partnership further in Note 4.
In November 2014, Sempra Renewables formed a joint venture with ConEdison Development by selling a 50-percent interest in the 75-MW Broken Bow 2 Wind project for $58 million in cash. Sempra Renewables recognized a pretax gain on the sale of $14 million ($8 million after-tax). Sempra Renewables acquired the rights to develop the Broken Bow 2 Wind project in September 2013.
Our remaining 50-percent interests in Copper Mountain Solar 2, Mesquite Solar 1, Copper Mountain Solar 3, and Broken Bow 2 Wind are accounted for under the equity method. Based on the nature of the underlying assets, these investments are considered in-substance real estate. Therefore, in accordance with applicable U.S. GAAP, for each of these investment transactions, the equity method investments were measured at their historical cost and no portion of the gains was attributable to a remeasurement of the retained investments to fair value.
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). The asset was classified as held for sale at December 31, 2012 and we recognized a pretax gain on sale of $74 million ($44 million after-tax), included in Gain on Sale of Equity Interests and Assets on our Consolidated Statement of Operations in 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 under “Other Commitments – Sempra Natural Gas.”
Asset Held For Sale, Power Plant
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.
In January 2014, management approved a formal plan to market and sell the remaining 625-MW block of the Mesquite Power plant, and in October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining block of the plant. We anticipate the sale will close in the first half of 2015, subject to obtaining third-party consents for the assignment to the buyer of a 25-year power sales contract associated with the plant.
At December 31, 2014, the carrying amount of the major classes of assets and related liability held for sale associated with the plant included the following:
| ASSET HELD FOR SALE, POWER PLANT |
| (Dollars in millions) | |
| | | December 31, |
| | | 2014 |
| Property, plant, and equipment, net | $ | 290 |
| Inventories | | 3 |
| Total assets held for sale | | 293 |
| Liability held for sale - asset retirement obligation(1) | | (6) |
| Total | $ | 287 |
| (1) | Included in Other Current Liabilities on the Consolidated Balance Sheet. |
The estimated fair value, including estimated costs to sell, exceeds the carrying amount at December 31, 2014.
Cameron LNG Holdings Joint Venture
On August 6, 2014, Sempra Natural Gas and its project partners, comprised of affiliates of GDF SUEZ S.A., Mitsui & Co., Ltd., and Mitsubishi Corporation (through a related company jointly established with Nippon Yusen Kabushiki Kaisha), provided their respective final investment decision with regard to the investment in the development, construction and operation of the natural gas liquefaction export facility at the terminal in Hackberry, Louisiana, owned by Cameron LNG, LLC (Cameron LNG). The Cameron liquefaction project utilizes Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability of 1.5 billion cubic feet (Bcf) per day. The current Cameron liquefaction project is 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. Commercial operation of all three trains is expected to commence in 2018, with the first year of full operations in 2019. The effective date of the Cameron LNG joint venture, Cameron LNG Holdings, LLC (Cameron LNG Holdings), among Sempra Energy and its project partners occurred on October 1, 2014 after satisfaction of various conditions, including receipt of final regulatory approval and satisfaction of conditions precedent to the first disbursement of the project financing.
Our equity in Cameron LNG Holdings was derived from our contribution of Cameron LNG to the joint venture at its historical carrying value. Each of the partners were issued equity interests in Cameron LNG Holdings in an aggregate of 49.8 percent. Cameron LNG thereby ceased to be wholly owned by Sempra Natural Gas, which retained a 50.2 percent interest in Cameron LNG Holdings. As of the October 1, 2014 effective date, Sempra Natural Gas began to account for its investment in Cameron LNG Holdings under the equity method. Sempra Energy did not recognize a gain or loss related to the contribution of Cameron LNG at cost to the joint venture.
In May 2012, Sempra Natural Gas acquired 100 percent of the outstanding common stock of Willmut Gas, a regulated natural gas distribution utility with 19,000 customer meters in Hattiesburg, Mississippi. Willmut Gas was purchased for $19 million in cash and the assumption of $10 million of liabilities. Included in the acquisition was $17 million in net property, plant and equipment. As a result of the acquisition, we recorded $10 million of goodwill.
NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES
We generally account for investments under the equity method when we have significant influence over, but do not have control of, these entities. In these cases, our pro rata shares of the entities’ net assets are included in Investments on the Consolidated Balance Sheets. We adjust each investment for our share of each investee’s earnings or losses, dividends, and other comprehensive income or loss.
We evaluate the carrying value of unconsolidated entities for impairment under the U.S. GAAP provisions for equity method investments.
We provide the carrying value of our investments and earnings (losses) on these investments below:
| EQUITY METHOD AND OTHER INVESTMENT BALANCES |
| (Dollars in millions) |
| | | December 31, |
| | | 2014 | 2013 |
| Sempra South American Utilities: | | | | |
| Eletrans(1) | $ | (8) | $ | (3) |
| Sempra Mexico: | | | | |
| Energía Sierra Juárez(2) | | 25 | | ― |
| Gasoductos de Chihuahua(3) | | 409 | | 379 |
| Sempra Renewables: | | | | |
| Wind: | | | | |
| Auwahi Wind | | 45 | | 53 |
| Broken Bow 2 Wind | | 44 | | ― |
| Cedar Creek 2 Wind | | 82 | | 92 |
| Flat Ridge 2 Wind | | 284 | | 292 |
| Fowler Ridge 2 Wind | | 46 | | 51 |
| Mehoopany Wind | | 82 | | 85 |
| Solar: | | | | |
| California solar partnership | | 125 | | ― |
| Copper Mountain Solar 2 | | 61 | | 67 |
| Copper Mountain Solar 3 | | 56 | | ― |
| Mesquite Solar 1 | | 86 | | 67 |
| Sempra Natural Gas: | | | | |
| Cameron LNG Holdings(4) | | 1,007 | | ― |
| Rockies Express Pipeline LLC(5) | | 340 | | 329 |
| Parent and other: | | | | |
| RBS Sempra Commodities LLP | | 71 | | 73 |
| Total equity method investments | | 2,755 | | 1,485 |
| Other(6) | | 93 | | 90 |
| Total | $ | 2,848 | $ | 1,575 |
| (1) | Includes losses on forward exchange contracts as we discuss below. |
| (2) | The carrying value of our equity method investment is $12 million higher than the underlying equity in the net assets of the investee at December 31, 2014 due to the remeasurement of our retained investment to fair value. |
| (3) | The carrying value of our equity method investment is $65 million higher than the underlying equity in the net assets of the investee at December 31, 2014 and 2013 due to equity method goodwill. |
| (4) | The carrying value of our equity method investment is $94 million higher than the underlying equity in the net assets of the investee at December 31, 2014 primarily due to guarantees as we discuss below. |
| (5) | The carrying value of our equity method investment is $369 million and $382 million lower than the underlying equity in the net assets of the investee at December 31, 2014 and 2013, respectively, due to an impairment charge recorded in 2012. |
| (6) | Other includes Sempra Natural Gas' $77 million investment in industrial development bonds at Mississippi Hub at both December 31, 2014 and 2013. |
| EARNINGS (LOSSES) FROM EQUITY METHOD INVESTMENTS |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Earnings (losses) recorded before income tax: | | | | | | |
| Sempra Renewables: | | | | | | |
| Wind: | | | | | | |
| Auwahi Wind | $ | 4 | $ | 4 | $ | ― |
| Cedar Creek 2 Wind | | (3) | | (4) | | (4) |
| Flat Ridge 2 Wind | | (7) | | (8) | | 1 |
| Fowler Ridge 2 Wind | | 2 | | (3) | | (3) |
| Mehoopany Wind | | (1) | | (2) | | ― |
| Solar: | | | | | | |
| California solar partnership | | 6 | | ― | | ― |
| Copper Mountain Solar 2 | | 3 | | ― | | ― |
| Copper Mountain Solar 3 | | 2 | | ― | | ― |
| Mesquite Solar 1 | | 14 | | 1 | | ― |
| Sempra Natural Gas: | | | | | | |
| Cameron LNG Holdings | | 2 | | ― | | ― |
| Rockies Express Pipeline LLC: | | | | | | |
| Impairment | | ― | | ― | | (400) |
| Income tax make-whole payment received | | ― | | ― | | 41 |
| Other equity earnings | | 60 | | 47 | | 47 |
| Parent and other: | | | | | | |
| RBS Sempra Commodities LLP | | (2) | | (3) | | ― |
| Other | | 1 | | (1) | | (1) |
| | $ | 81 | $ | 31 | $ | (319) |
| | | | | | | | |
| Earnings (losses) recorded net of income tax(1): | | | | | | |
| Sempra South American Utilities: | | | | | | |
| Sodigas Pampeana and Sodigas Sur | $ | ― | $ | (11) | $ | ― |
| Eletrans | | (4) | | (4) | | ― |
| Sempra Mexico: | | | | | | |
| Energía Sierra Juárez | | 3 | | ― | | ― |
| Gasoductos de Chihuahua | | 39 | | 39 | | 36 |
| | | $ | 38 | $ | 24 | $ | 36 |
| (1) | As the earnings (losses) from these investments are recorded net of income tax, they are presented below the income tax expense line, so as not to impact our effective income tax rate. |
Our share of the undistributed earnings of equity method investments was $187 million and $129 million at December 31, 2014 and 2013, respectively. The December 31, 2014 and 2013 balances do not include remaining distributions of $71 million and $73 million, respectively, associated with our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities) and expected to be received from the partnership as it is dissolved, as we discuss below.
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 December 2006, we decided to sell these investments and actively pursued their sale since that time. 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 Consolidated Statement of Operations for the year ended December 31, 2013. In June 2013, we completed the sale of our Argentine investments for $13 million in cash and recorded an additional $7 million loss ($4 million after-tax) on the sale, which is also included in Equity Earnings, Net of Income Tax.
As a result of the devaluation of the Argentine peso at the end of 2001 and subsequent changes in the value of the peso, Sempra South American Utilities had reduced the carrying value of its investments by a cumulative total of $270 million prior to the sale. These noncash adjustments, based on fluctuations in the value of the Argentine peso, did not affect earnings, but were recorded in Comprehensive Income and Accumulated Other Comprehensive Income (Loss). As a result of the sale of our investments, this cumulative foreign currency translation adjustment was reclassified to Equity Earnings, Net of Income Tax, where it was substantially offset by the elimination of a $250 million accrued liability established in 2006.
In 2013, Chilquinta Energía entered into two 50-percent owned joint ventures, Eletrans S.A. and Eletrans II S.A. (collectively, Eletrans), with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct four transmission lines in Chile. In 2013, Eletrans entered into forward exchange contracts to manage the foreign currency exchange rate risk of the Chilean Unidad de Fomento (CLF) relative to the U.S. dollar, related to certain construction commitments that are denominated in CLF. The forward exchange contracts settle based on anticipated payments to vendors, generally monthly, ending in July 2018. We recorded $4 million of equity losses related to these forward contracts in both 2014 and 2013 in Equity Earnings, Net of Income Tax on the Consolidated Statements of Operations.
Sempra Mexico owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company). The joint venture operates several natural gas pipelines and propane systems in Mexico and is developing natural gas pipelines, an ethane transport system and other energy infrastructure. Sempra Mexico acquired its investment in Gasoductos de Chihuahua as part of the purchase of Mexican pipeline and natural gas infrastructure assets in 2010.
In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V., as we discuss further in Note 3.
With the exception of Copper Mountain Solar 1, which it wholly owns, Sempra Renewables has 50-percent interests in wind and solar energy generation facilities in operation or under construction in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nebraska, Nevada, and Pennsylvania. The generating capacities of the facilities in operation are contracted under long-term power purchase agreements. These facilities are accounted for under the equity method.
Sempra Renewables formed joint ventures with ConEdison Development by selling 50-percent interests in its Copper Mountain Solar 2 and Mesquite Solar 1 facilities in 2013 and its Copper Mountain Solar 3 and Broken Bow 2 Wind facilities in 2014. We discuss these joint ventures further in Notes 3 and 5.
In May 2014, Sempra Renewables invested $121 million (as adjusted for financial position at closing) to become a 50-percent partner with ConEdison Development in four fully operating solar facilities in California. The joint venture includes 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.
Rockies Express
Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates a natural gas pipeline, REX, that links the Rocky Mountain region to the upper Midwest and the eastern United States. In November 2012, Kinder Morgan Energy Partners L.P. (KMP) sold its 50-percent interest in Rockies Express, as part of a larger asset group, to Tallgrass Energy Partners, L.P. (Tallgrass). Phillips 66 owns the remaining 25-percent interest. Our total investment in Rockies Express is accounted for as an equity method investment.
The general partner of KMP was Kinder Morgan, Inc. (KMI). As a condition of KMI receiving antitrust approval from the Federal Trade Commission (FTC) for its acquisition of El Paso Corporation, KMI agreed to divest certain assets in its natural gas pipeline group. Included in the asset group, as noted above, was KMP’s interest in Rockies Express. KMP recorded remeasurement losses during 2012 associated with these operations (classified as discontinued operations by KMP). In 2012, we recorded impairments of our partnership investment in Rockies Express of $300 million ($179 million after-tax) and $100 million ($60 million after-tax) in the second and third quarters, respectively, which are included in Equity Earnings (Losses), Before Income Tax on the Consolidated Statement of Operations. Our remaining carrying value in Rockies Express at December 31, 2014 is $340 million. We recorded the write-downs in 2012 as a result of our estimate of fair value for our investment at the reporting date and our conclusion that the impairments were other-than-temporary, as required by U.S. GAAP. We discuss the fair value measurement of our investment in Rockies Express in Note 10.
For income tax purposes, upon KMP’s sale of its 50-percent interest in Rockies Express, the partnership was considered terminated under federal tax law and a new partnership immediately formed which triggered a restart of depreciation method on the partnership’s remaining tax basis of its tangible assets. As required by the LLC agreement, KMP made a cash make-whole payment to Sempra Natural Gas of $41 million in November 2012, which was recorded as equity income from Rockies Express.
Cameron LNG
October 1, 2014 was the effective date of the formation of a joint venture partnership among Sempra Energy and three project partners involving Sempra Natural Gas' Cameron LNG facility in Louisiana, as we discuss in Note 3. As of October 1, 2014, Sempra Natural Gas began accounting for its investment in Cameron LNG Holdings under the equity method.
Cameron LNG Holdings Joint Venture Financing
General. On August 6, 2014, Cameron LNG entered into finance documents (collectively, Loan Facility Agreements) for senior secured financing in an initial aggregate principal amount of up to $7.4 billion under three debt facilities provided by the Japan Bank for International Cooperation (JBIC) and 29 international commercial banks, some of which will benefit from insurance coverage provided by Nippon Export and Investment Insurance (NEXI).
The Cameron LNG Loan Facility Agreements and related finance documents provide senior secured term loans with a maturity date of July 15, 2030. The proceeds of the loans will be used for financing the cost of development and construction of the three-train Cameron LNG project. The Loan Facility Agreements and related finance documents contain customary representations and affirmative and negative covenants for project finance facilities of this kind with the lenders of the type participating in the Cameron LNG financing.
On August 6, 2014, Sempra Energy entered into a completion agreement in favor of HSBC Bank USA, National Association, as security trustee for the benefit of all of Cameron LNG Holdings’ creditors under the Loan Facility Agreements. Pursuant to this completion agreement, Sempra Energy has severally guaranteed 50.2 percent of Cameron LNG Holdings’ senior debt obligations under the Loan Facility Agreements, or a maximum principal amount of $3.7 billion. Completion guarantees for the remaining 49.8 percent of Cameron LNG Holdings’ senior secured financing have been provided by the other project partners. The occurrence of the effectiveness of the Cameron LNG Holdings joint venture on October 1, 2014, as further described in Note 3, was a condition precedent to first disbursement of funds under the Loan Facility Agreements. The Sempra Energy completion guarantee of 50.2 percent of the Cameron LNG Holdings financing also became effective upon effectiveness of the Cameron LNG Holdings joint venture. Sempra Energy’s completion agreement and guarantee will terminate upon financial completion of the three-train Cameron LNG project, which is subject to satisfaction of certain conditions, including all three trains achieving commercial operations and meeting certain operational performance tests. Financial completion is scheduled for the second half of 2019. Sempra Energy recorded a liability of $82 million on October 1, 2014 for the fair value of its obligations associated with the debt reserve account requirements, which constitute guarantees. This liability is being amortized over the duration of the guarantees using the straight-line method.
On August 6, 2014, Sempra Energy and the other project partners entered into a transfer restrictions agreement with Société Générale, as intercreditor agent for the lenders under the Loan Facility Agreements. Pursuant to the transfer restriction agreement, Sempra Energy agreed to certain restrictions on its ability to dispose of Sempra Energy’s indirect fully diluted economic and beneficial ownership interests in Cameron LNG. These restrictions vary over time. Prior to financial completion of the three-train Cameron LNG project, Sempra Energy must retain 37.65 percent of such interest in Cameron LNG. Starting six months after financial completion of the three-train Cameron LNG project, Sempra Energy must retain at least 10 percent of the indirect fully diluted economic and beneficial ownership interest in Cameron LNG. At all times, the Sempra Energy affiliate that is the direct member in the Cameron LNG joint venture must be controlled by Sempra Energy and must have direct ownership of 50.2 percent of the Cameron LNG joint venture.
Interest. The weighted average all-in cost of the loans outstanding under all the Loan Facility Agreements (and based on certain assumptions as to timing of drawdown) is 1.59 percent per annum over LIBOR prior to financial completion of the project and 1.78 percent per annum over LIBOR following financial completion of the project. The Loan Facility Agreements require Cameron LNG to hedge 50 percent of outstanding borrowings to fix the interest rate, beginning in 2016. The hedges are to remain in place until the debt principal has been amortized by 50 percent. In November 2014, Cameron LNG entered into floating-to-fixed interest rate swaps for approximately $3.7 billion notional amount, resulting in an effective fixed rate of 3.19 percent.
Mandatory Prepayments. Cameron LNG Holdings must make mandatory prepayments of all loans made under the Loan Facility Agreements under certain circumstances, including: upon receipt of certain insurance proceeds and expropriation compensation; upon receipt of certain performance liquidated damages under Cameron LNG’s engineering, procurement and construction contract for the liquefaction terminal; in connection with the loss of its tolling agreements or export permits that result in a reduction of Cameron LNG’s debt service coverage ratios below a specified threshold; if it becomes unlawful in any applicable jurisdiction for a lender to fund or maintain its loans; or in connection with any mandatory prepayment of senior notes outstanding (if any).
The loans under the NEXI Covered Loan Facility Agreement and the loans held by JBIC under the JBIC Loan Facility Agreement are subject to certain additional mandatory prepayments that would be triggered if the Japanese sponsors fail to maintain certain ownership interests in Cameron LNG, if Cameron LNG’s Japanese tolling customers do not hold commitments for a certain quantum of nameplate capacity at the liquefaction terminal or if the aggregate annual contracted LNG commitments by Cameron LNG’s tolling customers to Japanese LNG buyers fall below a certain minimum threshold under certain circumstances.
Events of Default. Cameron LNG’s Loan Facility Agreements and related finance documents also contain events of default customary for such financings, including events of default for: failure to pay principal and interest on the due date; insolvency of Cameron LNG; abandonment of the project; expropriation; unenforceability or termination of the finance documents; and a failure to achieve financial completion of the project by a financial completion deadline date of September 30, 2021 (with up to additional 365 days extension beyond such date permitted in cases of force majeure). A delay in construction that results in a failure to achieve financial completion of the project by this financial completion deadline date would therefore result in an event of default under Cameron LNG’s financing and a potential demand on Sempra Energy’s guarantees.
Security. To support Cameron LNG’s obligations under the Loan Facility Agreements and related finance documents, Cameron LNG has granted security over all of its assets, subject to customary exceptions, and all equity interests in Cameron LNG have been pledged to HSBC Bank USA, National Association, as security trustee for the benefit of all Cameron LNG’s creditors. As a result, an enforcement action by the lenders taken in accordance with the finance documents could result in the exercise of such security interests by the lenders and the loss of ownership interests in Cameron LNG by Sempra Energy and the other project partners.
The security trustee under Cameron LNG’s financing can demand that a payment be made by Sempra Energy under its guarantees of Sempra Energy’s 50.2 percent share of senior debt obligations due and payable either on the date such amounts were due from Cameron LNG (taking into account cure periods) in the event of a failure by Cameron LNG to pay such senior debt obligations when they become due or within 10 business days in the event of an acceleration of senior debt obligations under the terms of the finance documents. If an event of default occurs under the Sempra Energy completion agreement, the security trustee can demand that Sempra Energy purchase its 50.2 percent share of all then outstanding senior debt obligations within five business days (other than in the case of a bankruptcy default, which is automatic).
RBS Sempra Commodities is a United Kingdom limited liability partnership formed by Sempra Energy and The Royal Bank of Scotland plc (RBS) in 2008 to own and operate the commodities-marketing businesses previously operated through wholly owned subsidiaries of Sempra Energy. We and RBS sold substantially all of the partnership’s businesses and assets in four separate transactions completed in 2010 and 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report miscellaneous costs since the sale of the business in Parent and Other.
We recorded $2 million and $3 million in pretax equity losses for the years ended December 31, 2014 and 2013, respectively, and no equity earnings or losses for the year ended December 31, 2012.
In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. In accordance with the Letter Agreement, we received distributions of $50 million in 2013. The investment balance of $71 million at December 31, 2014 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 15 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.
In connection with the Letter Agreement described above, we also released RBS from its indemnification obligations with respect to items for which J.P. Morgan Chase & Co. (JP Morgan), one of the buyers of the partnership’s businesses, has agreed to indemnify us.
SUMMARIZED FINANCIAL INFORMATION
We present summarized financial information below, aggregated for all of our equity method investments for the periods in which we were invested in the entity. The amounts below represent the aggregate financial position and results of operations of 100 percent of each of Sempra Energy’s equity method investments.
| SUMMARIZED FINANCIAL INFORMATION |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Gross revenues | $ | 1,296 | $ | 1,734 | $ | 2,138 |
| Operating expense | | (749) | | (1,287) | | (1,801) |
| Income from operations | | 547 | | 447 | | 337 |
| Interest expenses | | (298) | | (251) | | (218) |
| Net income/Earnings(1) | | 291 | | 222 | | (52) |
| | | | | | | | |
| | | | | At December 31, |
| | | | | 2014 | 2013 |
| Current assets | $ | 865 | $ | 653 |
| Noncurrent assets | | 13,161 | | 9,439 |
| Current liabilities | | 1,131 | | 373 |
| Noncurrent liabilities | | 6,228 | | 4,547 |
| (1) | Except for Gasoductos de Chihuahua, Energía Sierra Juárez, Eletrans and the Argentine investments, there was no income tax recorded by the entities, as they are primarily domestic partnerships. |
NOTE 5. DEBT AND CREDIT FACILITIES
At December 31, 2014, Sempra Energy Consolidated had an aggregate of $4.1 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper, the major components of which we detail below. Available unused credit on these lines at December 31, 2014 was $2.4 billion. Some of Sempra Energy’s subsidiaries, primarily our foreign operations, have additional general purpose credit facilities, aggregating $865 million at December 31, 2014. Available unused credit on these lines totaled $536 million at December 31, 2014.
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 December 31, 2014 and 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 December 31, 2014, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.
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 December 31, 2014 and 2013, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.
At December 31, 2014, Sempra Global had $1.3 billion of commercial paper outstanding supported by the facility. At December 31, 2013, Sempra Global had $200 million 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.
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 December 31, 2014 and 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 December 31, 2014, SDG&E and SoCalGas had $346 million and $50 million of commercial paper outstanding supported by the facility. Available unused credit on the line at December 31, 2014 was $312 million and $481 million at SDG&E and SoCalGas, respectively. SoCalGas’ availability reflects the impact of SDG&E’s use as of December 31, 2014 of the combined credit available on the line.
In June 2014, IEnova entered into an agreement for a $200 million, U.S. dollar-denominated, three-year corporate revolving credit facility to finance working capital and for general corporate purposes. The lender is Banco Santander, (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander Mexico. At December 31, 2014, IEnova had $145 million of outstanding borrowings supported by the facility, and available unused credit on the line was $55 million.
In August 2014, IEnova entered into an agreement for a $100 million, U.S. dollar-denominated, three-year corporate revolving credit facility to finance working capital and for general corporate purposes. The lender is Sumitomo Mitsui Banking Corporation. At December 31, 2014, IEnova had $51 million of outstanding borrowings supported by the facility, and available unused credit on the line was $49 million.
GUARANTEES
Sempra Renewables
Sempra Renewables and BP Wind Energy each currently hold 50-percent interests in Flat Ridge 2. The project obtained construction financing in December 2012, and proceeds from the loans were used to return $148 million of each owner’s joint venture investment in 2012. In March 2013, the construction financing was converted into permanent financing consisting of a term loan and a fixed-rate note. The term loan of $242 million expires in June 2023 and the fixed rate note of $110 million expires in June 2035. The financing agreement requires Sempra Renewables and BP Wind Energy, severally for each partner’s 50-percent interest, to return cash to the project in the event that the project does not meet certain cash flow criteria or in the event that the project’s debt service, operation and maintenance and firm transmission and production tax credits reserve accounts are not maintained at specific thresholds. Sempra Renewables recorded a liability of $3 million in 2013 for the fair value of its obligations associated with the cash flow requirements, which constitutes a guarantee. The liability is being amortized over its expected life. The outstanding loans are not guaranteed by the partners.
Sempra Renewables and BP Wind Energy each currently hold 50-percent interests in Mehoopany Wind. The project obtained construction financing in June 2012, and proceeds from the loans were used to return $13 million and $17 million of each owner’s joint venture investment in 2013 and 2012, respectively. In May 2013, the construction financing was converted into permanent financing consisting of a term loan. The term loan of $162 million expires in May 2031. The financing agreement requires Sempra Renewables and BP Wind Energy, severally for each partner’s 50-percent interest, to return cash to the project in the event that the project does not meet certain cash flow criteria or in the event that the project’s debt service, operation and maintenance and production tax credits reserve accounts are not maintained at specific thresholds. Additionally, in conjunction with the term loan conversion, Sempra Renewables and BP Wind Energy have provided guarantees to the lenders in lieu of Mehoopany Wind funding a reserve account requirement. Sempra Renewables recorded liabilities of $11 million in 2013 for the fair value of its obligations associated with the cash flow and reserve account requirements, which constitute guarantees. The liabilities are being amortized over their expected lives. The outstanding loans are not guaranteed by the partners.
Sempra Energy entered into completion guarantees related to the financing of the Cameron LNG project, as we discuss in Note 4.
WEIGHTED AVERAGE INTEREST RATES
The weighted average interest rates on the total short-term debt outstanding at Sempra Energy Consolidated were 0.70 percent and 0.64 percent at December 31, 2014 and 2013, respectively. The weighted average interest rate on the total short-term debt outstanding was 0.27 percent and 0.25 percent at December 31, 2014 at SDG&E and SoCalGas, respectively. The weighted average interest rate at Sempra Energy at December 31, 2013 includes interest rates for the $200 million of commercial paper borrowings supported by the Sempra Global credit facility classified as long-term, as we discuss above.
The following tables show the detail and maturities of long-term debt outstanding:
| LONG-TERM DEBT |
| (Dollars in millions) |
| | | December 31, |
| | | 2014 | 2013 |
| SDG&E | | | | |
| First mortgage bonds: | | | | |
| | 5.3% November 15, 2015 | $ | 250 | $ | 250 |
| | 1.65% July 1, 2018(1) | | 161 | | 161 |
| | 3% August 15, 2021 | | 350 | | 350 |
| | 3.6% September 1, 2023 | | 450 | | 450 |
| | 6% June 1, 2026 | | 250 | | 250 |
| | 5% to 5.25% December 1, 2027(1) | | 150 | | 150 |
| | 5.875% January and February 2034(1) | | 176 | | 176 |
| | 5.35% May 15, 2035 | | 250 | | 250 |
| | 6.125% September 15, 2037 | | 250 | | 250 |
| | 4% May 1, 2039(1) | | 75 | | 75 |
| | 6% June 1, 2039 | | 300 | | 300 |
| | 5.35% May 15, 2040 | | 250 | | 250 |
| | 4.5% August 15, 2040 | | 500 | | 500 |
| | 3.95% November 15, 2041 | | 250 | | 250 |
| | 4.3% April 1, 2042 | | 250 | | 250 |
| | | | 3,912 | | 3,912 |
| Other long-term debt (unsecured unless otherwise noted): | | | | |
| | 5.9% Notes June 1, 2014 | | ― | | 15 |
| | 5.3% Notes July 1, 2021(1) | | 39 | | 39 |
| | 5.5% Notes December 1, 2021(1) | | 60 | | 60 |
| | 4.9% Notes March 1, 2023(1) | | 25 | | 25 |
| | 5.2925% OMEC LLC loan | | | | |
| | payable 2013 through April 2019 (secured by plant assets) | | 325 | | 335 |
| | 366-day commercial paper borrowings May 2015, classified as long-term debt | | | | |
| | (0.40% weighted average at December 31, 2014) | | 100 | | ― |
| Capital lease obligations: | | | | |
| | Purchased-power agreements | | 233 | | 176 |
| | Other | | 1 | | 3 |
| | | | 783 | | 653 |
| | | | 4,695 | | 4,565 |
| Current portion of long-term debt | | (365) | | (29) |
| Unamortized discount on long-term debt | | (11) | | (11) |
| Total SDG&E | | 4,319 | | 4,525 |
| | | | | | |
| SoCalGas | | | | |
| First mortgage bonds: | | | | |
| | 5.5% March 15, 2014 | | ― | | 250 |
| | 5.45% April 15, 2018 | | 250 | | 250 |
| | 3.15% September 15, 2024 | | 500 | | ― |
| | 5.75% November 15, 2035 | | 250 | | 250 |
| | 5.125% November 15, 2040 | | 300 | | 300 |
| | 3.75% September 15, 2042 | | 350 | | 350 |
| | 4.45% March 15, 2044 | | 250 | | ― |
| | | | 1,900 | | 1,400 |
| Other long-term debt (unsecured): | | | | |
| | 4.75% Notes May 14, 2016(1) | | 8 | | 8 |
| | 5.67% Notes January 18, 2028 | | 5 | | 5 |
| Capital lease obligations | | 1 | | 2 |
| | | | 14 | | 15 |
| | | | 1,914 | | 1,415 |
| Current portion of long-term debt | | ― | | (252) |
| Unamortized discount on long-term debt | | (8) | | (4) |
| Total SoCalGas | | 1,906 | | 1,159 |
| LONG-TERM DEBT (CONTINUED) |
| (Dollars in millions) |
| | | December 31, |
| | | 2014 | 2013 |
| Sempra Energy | | | | |
| Other long-term debt (unsecured): | | | | |
| | 2% Notes March 15, 2014 | | ― | | 500 |
| | Notes at variable rates (1.01% at December 31, 2013) March 15, 2014 | | ― | | 300 |
| | 6.5% Notes June 1, 2016, including $300 at variable rates after fixed-to-floating | | | | |
| | rate swaps effective January 2011 (4.44% at December 31, 2014) | | 750 | | 750 |
| | 2.3% Notes April 1, 2017 | | 600 | | 600 |
| | 6.15% Notes June 15, 2018 | | 500 | | 500 |
| | 9.8% Notes February 15, 2019 | | 500 | | 500 |
| | 2.875% Notes October 1, 2022 | | 500 | | 500 |
| | 4.05% Notes December 1, 2023 | | 500 | | 500 |
| | 3.55% Notes June 15, 2024 | | 500 | | ― |
| | 6% Notes October 15, 2039 | | 750 | | 750 |
| Market value adjustments for interest rate swaps, net | | ― | | 12 |
| Build-to-suit lease(2) | | 75 | | 14 |
| Sempra Global | | | | |
| Other long-term debt (unsecured): | | | | |
| | Commercial paper borrowings at variable rates, classified as long-term debt | | | | |
| | (0.35% weighted average at December 31, 2013) | | ― | | 200 |
| Sempra South American Utilities | | | | |
| Other long-term debt (unsecured): | | | | |
| Chilquinta Energía | | | | |
| | 4.25% Series B Bonds October 30, 2030(1) | | 192 | | 209 |
| Luz del Sur | | | | |
| | Bank loans 5.05% to 6.41% payable 2016 through December 2018 | | 91 | | 70 |
| | Notes at 4.75% to 7.41% payable 2014 through September 2029 | | 345 | | 292 |
| | Other bonds at 3.77% to 4.59% payable 2020 through May 2022 | | 10 | | ― |
| Sempra Mexico | | | | |
| Other long-term debt (unsecured): | | | | |
| | Notes February 8, 2018 at variable rates (2.66% after floating-to-fixed rate cross-currency | | | | |
| | swaps effective February 2013) | | 88 | | 100 |
| | 6.3% Notes February 2, 2023 (4.12% after cross-currency swap) | | 265 | | 298 |
| | Notes at variable rates (1.28% at December 31, 2014) August 25, 2017(1)(3) | | 51 | | ― |
| Sempra Renewables | | | | |
| Other long-term debt (secured): | | | | |
| | Loan at variable rates payable 2014 through December 2028, including $74 at 4.54% | | | | |
| | after floating-to-fixed rate swaps effective June 2012 (2.74% at December 31, 2014)(1) | | 97 | | 104 |
| Sempra Natural Gas | | | | |
| First mortgage bonds (Mobile Gas): | | | | |
| | 4.14% September 30, 2021 | | 20 | | 20 |
| | 5% September 30, 2031 | | 42 | | 42 |
| Other long-term debt (unsecured unless otherwise noted): | | | | |
| | Notes at 2.87% to 3.51% October 1, 2016(1) | | 19 | | 18 |
| | 8.45% Notes payable 2014 through December 2017, secured | | 16 | | 21 |
| | 3.1% Notes December 30, 2018, secured(1) | | 5 | | 5 |
| | 4.5% Notes July 1, 2024, secured(1) | | 77 | | 77 |
| | Industrial development bonds at variable rates (0.05% at December 31, 2014) | | | | |
| | August 1, 2037, secured(1) | | 55 | | 55 |
| | | | 6,048 | | 6,437 |
| Current portion of long-term debt | | (104) | | (866) |
| Unamortized discount on long-term debt | | (9) | | (9) |
| Unamortized premium on long-term debt | | 7 | | 7 |
| Total other Sempra Energy | | 5,942 | | 5,569 |
| Total Sempra Energy Consolidated | $ | 12,167 | $ | 11,253 |
| (1) | Callable long-term debt not subject to make-whole provisions. |
| (2) | We discuss this lease in Note 15. |
| (3) | Classified as current portion of long-term debt. |
| MATURITIES OF LONG-TERM DEBT(1) |
| (Dollars in millions) |
| | | | | | Total |
| | | | | Other | Sempra |
| | | | | Sempra | Energy |
| | | SDG&E | SoCalGas | Energy | Consolidated |
| 2015 | $ | 360 | $ | ― | $ | 96 | $ | 456 |
| 2016 | | 10 | | 8 | | 845 | | 863 |
| 2017 | | 10 | | ― | | 670 | | 680 |
| 2018 | | 171 | | 250 | | 638 | | 1,059 |
| 2019 | | 285 | | ― | | 537 | | 822 |
| Thereafter | | 3,625 | | 1,655 | | 3,187 | | 8,467 |
| Total | $ | 4,461 | $ | 1,913 | $ | 5,973 | $ | 12,347 |
| (1) | Excludes capital lease obligations, build-to-suit lease and market value adjustments for interest rate swaps. |
Various long-term obligations totaling $5.9 billion at Sempra Energy at December 31, 2014 are unsecured. This includes unsecured long-term obligations totaling $224 million at SDG&E and $13 million at SoCalGas.
At the option of Sempra Energy, SDG&E and SoCalGas, certain debt is callable subject to premiums:
| CALLABLE LONG-TERM DEBT |
| (Dollars in millions) |
| | | | | Total |
| | | | Other | Sempra |
| | | | Sempra | Energy |
| | SDG&E | SoCalGas | Energy | Consolidated |
| Not subject to make-whole provisions | $ | 686 | $ | 8 | $ | 496 | $ | 1,190 |
| Subject to make-whole provisions | | 3,350 | | 1,900 | | 4,678 | | 9,928 |
In addition, the OMEC LLC project financing loan discussed in Note 1, with $325 million of outstanding borrowings at December 31, 2014, may be prepaid at the borrowers’ option.
The California Utilities issue first mortgage bonds secured by a lien on utility plant. The California Utilities may issue additional first mortgage bonds upon compliance with the provisions of their bond agreements (indentures). These indentures require, among other things, the satisfaction of pro forma earnings-coverage tests on first mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds, after giving effect to prior bond redemptions. The most restrictive of these tests (the property test) would permit the issuance, subject to CPUC authorization, of an additional $4.3 billion of first mortgage bonds at SDG&E and $0.9 billion at SoCalGas at December 31, 2014.
In September 2014, SoCalGas publicly offered and sold $500 million of 3.15-percent first mortgage bonds maturing in 2024. SoCalGas used the proceeds from this offering for the repayment of commercial paper and other general corporate purposes.
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 matured in March 2014.
INDUSTRIAL DEVELOPMENT BONDS
To secure an approved exemption from sales and use tax, Sempra Natural Gas has incurred through December 31, 2014, $257 million ($3 million in 2013, $53 million in 2012, $84 million in 2011, $42 million in 2010 and $75 million in 2009) out of a maximum available $265 million of long-term debt related to the construction and equipping of its Mississippi Hub natural gas storage facility. After a redemption of $180 million in December 2011, the debt balance remaining at December 31, 2014 is $77 million. The debt is payable to the Mississippi Business Finance Corporation (MBFC), and we recorded bonds receivable from the MBFC for the same amount. Both the financing obligation and the bonds receivable have interest rates of 4.5 percent and are due on July 1, 2024.
OTHER LONG-TERM DEBT
In June 2014, Sempra Energy publicly offered and sold $500 million of 3.55-percent, fixed rate notes maturing in 2024. Sempra Energy used the proceeds from this offering for the repayment of commercial paper.
In the second quarter of 2014, SDG&E issued $100 million of commercial paper maturing in May 2015, that is supported by the California Utilities’ credit facility discussed above and has a weighted average interest rate of 0.40 percent at December 31, 2014.
Sempra South American Utilities
Luz del Sur has outstanding corporate bonds and bank loans which are denominated in the local currency. During 2014, Luz del Sur publicly offered and sold $30 million of corporate bonds at 7.41 percent maturing in 2022, $50 million of corporate bonds at 6.69 percent maturing in 2024 and $50 million of corporate bonds at 6.88 percent maturing in 2029. Additionally, Luz del Sur drew bank loans in 2014 as follows:
| 2014 BANK LOAN DRAWS – LUZ DEL SUR |
| (Dollars in millions) |
| | | Amount at | | | |
| Month issued | issuance | Interest rate | | Maturity date |
| March | $ | 7 | 5.10% | | June 22, 2015 |
| March | | 14 | 5.35% | | September 24, 2015 |
| October | | 31 | 5.05% | | July 15, 2016 |
| October | | 36 | 6.00% | | December 27, 2016 |
In June 2014, Energía Sierra Juárez entered into a $240 million loan to project finance the construction of the wind project. The variable rate loan is secured by the project and will convert to an 18-year term loan upon completion of the first phase of the project. To partially moderate its exposure to interest rate changes associated with the term loan, Energía Sierra Juárez entered into floating-to-fixed interest rate swaps for 90 percent of the loan amount, which will result in an effective fixed rate of 6.1 percent. The swap is effective on the conversion to a term loan. The remaining 10 percent of principal bears interest at rates varying with market rates (0.16 percent at December 31, 2014). The loan agreement also provides for a $31.7 million letter of credit facility. Energía Sierra Juárez also entered into a separate, Peso-denominated credit facility for up to $35 million U.S. dollar equivalent to fund the value added tax of the project. On June 12, 2014, Energía Sierra Juárez drew down $82 million of the construction loan. On July 16, 2014, this $82 million of long-term debt and the related swaps were deconsolidated upon the sale of a 50-percent interest in Energía Sierra Juárez, as we discuss in Note 3.
On October 30, 2014, Sempra Renewables completed a private offering of an aggregate of $72 million in principal amount of 4.82-percent fixed rate notes maturing in 2039. Proceeds from this offering were used to finance its Broken Bow 2 Wind project. On November 5, 2014, this $72 million of long-term debt was deconsolidated upon the sale of a 50-percent interest in Broken Bow 2 Wind to ConEdison Development, which we discuss in Note 3.
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 (0.16 percent at December 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, Copper Mountain Solar 3 drew down $97 million from the loan. On March 13, 2014, this $97 million of long-term debt and the related swaps were deconsolidated upon the sale of a 50-percent interest in Copper Mountain Solar 3, as we discuss in Note 3.
We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 9.
Reconciliation of net U.S. statutory federal income tax rates to the effective income tax rates is as follows:
| RECONCILIATION OF FEDERAL INCOME TAX RATES TO EFFECTIVE INCOME TAX RATES |
| |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| U.S. federal statutory income tax rate | 35 | % | 35 | % | 35 | % |
| Utility depreciation | 5 | | 4 | | 6 | |
| U.S. tax on repatriation of foreign earnings | 2 | | ― | | ― | |
| Income tax restructuring related to IEnova stock offerings | ― | | 4 | | ― | |
| State income taxes, net of federal income tax benefit | ― | | 1 | | (1) | |
| Utility repairs expenditures | (5) | | (5) | | (8) | |
| Tax credits | (4) | | (3) | | (7) | |
| Self-developed software expenditures | (3) | | (3) | | (5) | |
| Non-U.S. earnings taxed at lower statutory income tax rates | (2) | | (3) | | (4) | |
| Allowance for equity funds used during construction | (2) | | (1) | | (4) | |
| Foreign exchange and inflation effects | (2) | | ― | | 1 | |
| Adjustments to prior years’ income tax items | (1) | | (3) | | (1) | |
| International tax reform | (1) | | 1 | | ― | |
| Life insurance contracts | ― | | ― | | (7) | |
| Other, net | (2) | | (1) | | 1 | |
| Effective income tax rate | 20 | % | 26 | % | 6 | % |
| SDG&E: | | | | | | |
| U.S. federal statutory income tax rate | 35 | % | 35 | % | 35 | % |
| State income taxes, net of federal income tax benefit | 5 | | 3 | | 4 | |
| Depreciation | 4 | | 5 | | 4 | |
| SONGS tax regulatory asset write-off | 2 | | ― | | ― | |
| Utility repairs expenditures | (4) | | (4) | | (4) | |
| Self-developed software expenditures | (3) | | (3) | | (3) | |
| Allowance for equity funds used during construction | (2) | | (2) | | (4) | |
| Adjustments to prior years’ income tax items | (2) | | (1) | | (3) | |
| Variable interest entity | (1) | | (1) | | (1) | |
| Other, net | ― | | (1) | | (1) | |
| Effective income tax rate | 34 | % | 31 | % | 27 | % |
| SoCalGas: | | | | | | |
| U.S. federal statutory income tax rate | 35 | % | 35 | % | 35 | % |
| Depreciation | 8 | | 6 | | 7 | |
| State income taxes, net of federal income tax benefit | 4 | | 4 | | 3 | |
| Utility repairs expenditures | (9) | | (9) | | (12) | |
| Self-developed software expenditures | (5) | | (6) | | (9) | |
| Adjustments to prior years’ income tax items | (2) | | (5) | | ― | |
| Allowance for equity funds used during construction | (2) | | (1) | | (2) | |
| Other, net | ― | | ― | | (1) | |
| Effective income tax rate | 29 | % | 24 | % | 21 | % |
In 2014, 2013 and 2012, non-U.S. earnings taxed at lower statutory income tax rates than the U.S. are primarily related to operations in Mexico, Chile and Peru.
In 2014, our effective income tax rate was affected by a $25 million tax benefit due to the release of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments. This benefit is included in “State Income Taxes, Net of Federal Income Tax Benefit” in the table above.
In addition, the effective income tax rates for Sempra Energy Consolidated and SDG&E were impacted in 2014 by a $17 million charge to reduce certain tax regulatory assets attributed to SDG&E’s investment in SONGS pursuant to a settlement agreement to resolve the CPUC’s Order Instituting Investigation (OII) into the SONGS outage that we discuss in Note 13.
Foreign exchange and inflation effects for Sempra Energy Consolidated in 2014 are primarily due to significant devaluation of the Mexican peso against the U.S. dollar in 2014.
In 2013, our effective income tax rate was affected by $63 million of income tax expense recorded in the first quarter of 2013 resulting from a corporate reorganization in connection with the IEnova stock offerings.
Utility repairs expenditures significantly affecting the effective income tax rates for Sempra Energy Consolidated, SDG&E and SoCalGas in 2014, 2013 and 2012 are due to a change in 2012 in the income tax treatment of certain repairs that are capitalized for financial statement purposes. The change in income tax treatment of certain repairs for electric transmission and distribution assets, which applied to SDG&E, was made pursuant to an Internal Revenue Service (IRS) Revenue Procedure providing a safe harbor for deducting certain repairs expenditures from taxable income when incurred for tax years beginning on or after January 1, 2011. The change in income tax treatment of certain repairs expenditures for gas plant assets, which applied to SoCalGas, was made pursuant to an IRS Revenue Procedure, which allows, under an Internal Revenue Code section, such expenditures to be deducted from taxable income when incurred.
Life insurance contracts significantly affected the effective tax rate for Sempra Energy Consolidated in 2012 primarily due to our decision in the second quarter of 2012 to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts.
In September 2013, the IRS and U.S. Department of the Treasury released final tangible property regulations on the capitalization and expensing rules applicable to expenditures for the acquisition and production of tangible property. Companies were required to conform their tax accounting methods and elect any safe harbors under the final regulations no later than the tax year beginning on January 1, 2014. Additionally, if a change in the company’s tax accounting methods was required to conform to the final regulations, the company was also required to adjust its deferred tax balances at December 31, 2013 for any tax adjustments required to bring all prior periods into compliance with the final regulations. We evaluated our tax accounting methods and deferred tax balances based on the guidance contained in the final tangible property regulations and determined that we are following the guidance in all material respects. Any adjustments to deferred taxes resulting from changes to comply with the final tangible property regulations would have a de minimis impact on the financial statements. Accordingly, we did not make any adjustment to our deferred tax balances at December 31, 2014 or December 31, 2013 based on the issuance of the final tangible property regulations.
For SDG&E and SoCalGas, 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 results in impacting 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 assets |
The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico and Sempra Natural Gas has similar flow-through treatment.
We use the deferral method for investment tax credits (ITC). For certain solar and wind generating assets placed into service during 2012, we elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting was applied. Grant accounting for cash grants is very similar to the deferral method of accounting for ITC, the primary difference being the recording of a cash grant receivable instead of an income tax receivable.
Under the deferral method of accounting for ITC and under grant accounting for cash grants, we record a deferred income tax benefit, on day one, which is reflected in income tax expense by recording a deferred income tax asset during the year the renewable energy assets are placed in service. This deferred income tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the day-one basis difference. The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced by 50 percent for grants and not at all for ITC.
Conversion of ITC to cash is generally dependent on reducing income tax payments and thus the existence of a U.S. federal net operating loss (NOL) carryforward can result in delaying this conversion.
The geographic components of Income Before Income Taxes and Equity Earnings of Certain Unconsolidated Subsidiaries at Sempra Energy are as follows:
| | Years ended December 31, |
| (Dollars in millions) | 2014 | 2013 | 2012 |
| U.S. | $ | 1,014 | $ | 941 | $ | 442 |
| Non-U.S. | | 510 | | 489 | | 501 |
| Total | $ | 1,524 | $ | 1,430 | $ | 943 |
The components of income tax expense are as follows:
| INCOME TAX EXPENSE (BENEFIT) |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| Current: | | | | | | |
| U.S. Federal | $ | (10) | $ | (70) | $ | (36) |
| U.S. State | | (7) | | (5) | | (6) |
| Non-U.S. | | 171 | | 107 | | 144 |
| Total | | 154 | | 32 | | 102 |
| Deferred: | | | | | | |
| U.S. Federal | | 237 | | 275 | | (63) |
| U.S. State | | 4 | | 15 | | 3 |
| Non-U.S. | | (91) | | 48 | | 20 |
| Total | | 150 | | 338 | | (40) |
| Deferred investment tax credits | | (4) | | (4) | | (3) |
| Total income tax expense | $ | 300 | $ | 366 | $ | 59 |
| SDG&E: | | | | | | |
| Current: | | | | | | |
| U.S. Federal | $ | (5) | $ | 9 | $ | (109) |
| U.S. State | | 52 | | 11 | | 14 |
| Total | | 47 | | 20 | | (95) |
| Deferred: | | | | | | |
| U.S. Federal | | 220 | | 149 | | 255 |
| U.S. State | | 5 | | 24 | | 30 |
| Total | | 225 | | 173 | | 285 |
| Deferred investment tax credits | | (2) | | (2) | | ― |
| Total income tax expense | $ | 270 | $ | 191 | $ | 190 |
| SoCalGas: | | | | | | |
| Current: | | | | | | |
| U.S. Federal | $ | 2 | $ | 4 | $ | (73) |
| U.S. State | | 7 | | (5) | | 24 |
| Total | | 9 | | (1) | | (49) |
| Deferred: | | | | | | |
| U.S. Federal | | 117 | | 103 | | 136 |
| U.S. State | | 15 | | 16 | | (6) |
| Total | | 132 | | 119 | | 130 |
| Deferred investment tax credits | | (2) | | (2) | | (2) |
| Total income tax expense | $ | 139 | $ | 116 | $ | 79 |
We show the components of deferred income taxes at December 31 for Sempra Energy Consolidated, SDG&E and SoCalGas in the tables below:
| DEFERRED INCOME TAXES FOR SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | December 31, |
| | | 2014 | 2013 |
| Deferred income tax liabilities: | | | | |
| Differences in financial and tax bases of depreciable and amortizable assets | $ | 4,074 | $ | 3,951 |
| Regulatory balancing accounts | | 915 | | 663 |
| Property taxes | | 57 | | 50 |
| Differences in financial and tax bases of partnership interests(1) | | 650 | | 256 |
| Other deferred income tax liabilities | | 53 | | 95 |
| Total deferred income tax liabilities | | 5,749 | | 5,015 |
| Deferred income tax assets: | | | | |
| Tax credits | | 276 | | 105 |
| Equity losses | | 40 | | 16 |
| Net operating losses | | 1,908 | | 2,023 |
| Compensation-related items | | 244 | | 128 |
| Postretirement benefits | | 433 | | 264 |
| Other deferred income tax assets | | 97 | | 22 |
| State income taxes | | 19 | | 30 |
| Litigation and other accruals not yet deductible | | 73 | | 20 |
| Deferred income tax assets before valuation allowances | | 3,090 | | 2,608 |
| Less: valuation allowances | | 39 | | 96 |
| Total deferred income tax assets | | 3,051 | | 2,512 |
| Net deferred income tax liability(2) | $ | 2,698 | $ | 2,503 |
| (1) | Amounts primarily represent differences in financial and tax bases of depreciable and amortizable assets within our partnerships. |
| (2) | Our policy is to show deferred income taxes of VIEs on a net basis, including valuation allowances. See table “Amounts Associated with Otay Mesa VIE” in Note 1 for further information. |
| DEFERRED INCOME TAXES FOR SDG&E AND SOCALGAS |
| (Dollars in millions) |
| | | SDG&E | SoCalGas |
| | | December 31, | December 31, |
| | | 2014 | 2013 | 2014 | 2013 |
| Deferred income tax liabilities: | | | | | | | | |
| Differences in financial and tax bases of | | | | | | | | |
| utility plant and other assets | $ | 2,181 | $ | 2,040 | $ | 1,194 | $ | 1,045 |
| Regulatory balancing accounts | | 441 | | 411 | | 481 | | 265 |
| Property taxes | | 39 | | 36 | | 18 | | 16 |
| Other | | 5 | | 28 | | 10 | | 6 |
| Total deferred income tax liabilities | | 2,666 | | 2,515 | | 1,703 | | 1,332 |
| Deferred income tax assets: | | | | | | | | |
| Net operating losses | | 297 | | 440 | | 64 | | 65 |
| Postretirement benefits | | 85 | | 57 | | 261 | | 126 |
| Compensation-related items | | 8 | | 13 | | 40 | | 38 |
| State income taxes | | 27 | | 22 | | 11 | | 10 |
| Litigation and other accruals not yet deductible | | 39 | | 45 | | 23 | | 27 |
| Other | | 36 | | 20 | | 39 | | 28 |
| Total deferred income tax assets | | 492 | | 597 | | 438 | | 294 |
| Net deferred income tax liability(1) | $ | 2,174 | $ | 1,918 | $ | 1,265 | $ | 1,038 |
| (1) | Our policy is to show deferred income taxes of VIEs on a net basis, including valuation allowances. See table “Amounts Associated with Otay Mesa VIE” in Note 1 for further information. |
The net deferred income tax liabilities are recorded on the Consolidated Balance Sheets at December 31 as follows:
| NET DEFERRED INCOME TAX LIABILITY |
| (Dollars in millions) |
| | Sempra Energy | | | | |
| | Consolidated | SDG&E | SoCalGas |
| | 2014 | 2013 | 2014 | 2013 | 2014 | 2013 |
| Current (asset) liability | $ | (305) | $ | (301) | $ | 53 | $ | (103) | $ | 53 | $ | 45 |
| Noncurrent liability | | 3,003 | | 2,804 | | 2,121 | | 2,021 | | 1,212 | | 993 |
| Total | $ | 2,698 | $ | 2,503 | $ | 2,174 | $ | 1,918 | $ | 1,265 | $ | 1,038 |
At December 31, 2014, Sempra Energy has recorded a valuation allowance against a portion of its total deferred income tax assets, as shown above in the “Deferred Income Taxes for Sempra Energy Consolidated” table. A valuation allowance is recorded when, based on more-likely-than-not criteria, negative evidence outweighs positive evidence with regard to our ability to realize a deferred income tax asset in the future. Of the valuation allowances recorded to date, the negative evidence outweighs the positive evidence primarily due to cumulative pretax losses in various U.S. state and non-U.S. jurisdictions resulting in a deferred income tax asset related to NOLs, as discussed below, that we currently do not believe will be realized on a more-likely-than-not basis. At both Sempra Energy and SDG&E, deferred income taxes for variable interest entities are shown on a net basis. Therefore, valuation allowances of $48 million at December 31, 2014 and $60 million at December 31, 2013 related to variable interest entities are not reflected in the table above. Of Sempra Energy’s total valuation allowance of $39 million at December 31, 2014, $8 million is related to non-U.S. NOLs and $31 million to U.S. state NOLs. Of Sempra Energy’s total valuation allowance of $96 million at December 31, 2013, $12 million is related to non U.S. NOLs and $84 million to U.S. state NOLs. The total valuation allowance decreased in 2014 primarily due to release of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments and expiration of the carryover periods of certain U.S. state and non-U.S. NOLs.
Sempra Energy’s U.S. subsidiaries had $4.9 billion of unused U.S. federal consolidated NOLs that will begin to expire in 2031, $182 million of unused U.S. federal consolidated general business tax credits that will begin to expire in 2032 and $52 million of unused foreign tax credits that expire in 2024. Included in the NOL amount is $266 million of excess tax deductions related to employee stock expense for which a benefit will be recorded to additional paid in capital when realized. When assessing whether a tax benefit relating to employee stock expense has been realized, we follow the tax law ordering method, under which current year share-based compensation deductions are assumed to be utilized before net operating loss carryforwards and other tax attributes. We have recorded deferred income tax benefits on these NOLs, and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not basis.
At December 31, 2014, SDG&E had $867 million of unused U.S. federal NOL which expires in 2032 and $12 million of unused U.S. federal general business tax credits which begin to expire in 2031. At December 31, 2014, SoCalGas had $210 million of unused U.S. federal NOLs which begin to expire in 2032 and $11 million of unused U.S. federal general business tax credits which begin to expire in 2031. We have recorded deferred income tax benefits on these NOLs and tax credits, in total, because we currently believe they will be realized on a more-likely-than-not basis.
Sempra Energy’s U.S. subsidiaries had $2.7 billion of unused U.S. state NOLs, primarily in Alabama, California, Connecticut, District of Columbia, Indiana, Kansas, Louisiana, Minnesota, Missouri, Mississippi, Nebraska and Pennsylvania. These U.S. state NOLs expire between 2015 and 2034. We have not recorded deferred income tax benefits on a portion of Sempra Energy’s total U.S. state NOLs because we currently believe they will not be realized on a more-likely-than-not basis, as discussed above. Sempra Natural Gas and its project partners are currently developing a natural gas liquefaction export facility at the Cameron LNG terminal in Louisiana. In 2014 we released $25 million of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments. Sempra Energy’s U.S. subsidiaries also had $31 million of unused U.S. state general business tax credits that begin to expire in 2016. We have recorded deferred income tax benefits on these tax credits, in total, because we currently believe they will be realized on a more-likely-than-not basis.
At December 31, 2014, Sempra Energy’s non-U.S. subsidiaries had $312 million of unused NOLs available to utilize in the future to reduce Sempra Energy’s future non-U.S. income tax expense related to our companies in Mexico and the Netherlands. The carryforward periods for our non-U.S. unused NOLs expire between 2015 and 2024. We have not recorded deferred income tax benefits on a portion of Sempra Energy’s total non-U.S. NOLs because we currently believe they will not be realized on a more-likely-than-not basis, as discussed above.
At December 31, 2014, Sempra Energy had not recognized a U.S. deferred income tax liability related to a $3.6 billion basis difference between its financial statement and income tax investment amount in its non-U.S. subsidiaries and non-U.S. corporate joint ventures. This basis difference consists of $3.6 billion of cumulative undistributed earnings that we expect to reinvest indefinitely outside of the U.S. These cumulative undistributed earnings have previously been reinvested or will be reinvested in active non-U.S. operations, thus we do not intend to use these earnings as a source of funding for U.S. operations. It is not practical to determine the hypothetical unrecognized amount of U.S. deferred income taxes that might be payable if the cumulative undistributed earnings were eventually distributed or the investments were sold.
Following is a summary of unrecognized income tax benefits:
| SUMMARY OF UNRECOGNIZED INCOME TAX BENEFITS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| Total | $ | 117 | $ | 90 | $ | 82 |
| Of the total, amounts related to tax positions that, | | | | | | |
| if recognized in future years, would | | | | | | |
| decrease the effective tax rate | $ | (114) | $ | (86) | $ | (81) |
| increase the effective tax rate | | 21 | | 19 | | 16 |
| SDG&E: | | | | | | |
| Total | $ | 14 | $ | 17 | $ | 12 |
| Of the total, amounts related to tax positions that, | | | | | | |
| if recognized in future years, would | | | | | | |
| decrease the effective tax rate | $ | (11) | $ | (14) | $ | (12) |
| increase the effective tax rate | | 6 | | 11 | | 12 |
| SoCalGas: | | | | | | |
| Total | $ | 19 | $ | 13 | $ | 5 |
| Of the total, amounts related to tax positions that, | | | | | | |
| if recognized in future years, would | | | | | | |
| decrease the effective tax rate | $ | (19) | $ | (13) | $ | (5) |
| increase the effective tax rate | | 15 | | 8 | | 4 |
Following is a reconciliation of the changes in unrecognized income tax benefits for the years ended December 31:
| RECONCILIATION OF UNRECOGNIZED INCOME TAX BENEFITS |
| (Dollars in millions) |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| Balance as of January 1 | $ | 90 | $ | 82 | $ | 72 |
| Increase in prior period tax positions | | 37 | | 26 | | 2 |
| Decrease in prior period tax positions | | ― | | (24) | | (1) |
| Increase in current period tax positions | | 5 | | 7 | | 10 |
| Settlements with taxing authorities | | (15) | | (1) | | (1) |
| Balance as of December 31 | $ | 117 | $ | 90 | $ | 82 |
| SDG&E: | | | | | | |
| Balance as of January 1 | $ | 17 | $ | 12 | $ | 7 |
| Increase in prior period tax positions | | 2 | | 7 | | 1 |
| Decrease in prior period tax positions | | ― | | (4) | | ― |
| Increase in current period tax positions | | ― | | 2 | | 4 |
| Settlements with taxing authorities | | (5) | | ― | | ― |
| Balance as of December 31 | $ | 14 | $ | 17 | $ | 12 |
| SoCalGas: | | | | | | |
| Balance as of January 1 | $ | 13 | $ | 5 | $ | ― |
| Increase in prior period tax positions | | 2 | | 4 | | ― |
| Increase in current period tax positions | | 4 | | 5 | | 5 |
| Settlements with taxing authorities | | ― | | (1) | | ― |
| Balance as of December 31 | $ | 19 | $ | 13 | $ | 5 |
It is reasonably possible that within the next 12 months, unrecognized income tax benefits could decrease due to the following:
| POSSIBLE DECREASES IN UNRECOGNIZED INCOME TAX BENEFITS WITHIN 12 MONTHS |
| (Dollars in millions) |
| | At December 31, |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | |
| Expiration of statutes of limitations on tax assessments | $ | ― | $ | (7) | $ | (7) |
| Potential resolution of audit issues with various | | | | | | |
| U.S. federal, state and local and non-U.S. taxing authorities | | (61) | | (63) | | (10) |
| | $ | (61) | $ | (70) | $ | (17) |
| SDG&E: | | | | | | |
| Potential resolution of audit issues with various | | | | | | |
| U.S. federal, state and local and non-U.S. taxing authorities | $ | (9) | $ | (14) | $ | (5) |
| SoCalGas: | | | | | | |
| Potential resolution of audit issues with various | | | | | | |
| U.S. federal, state and local and non-U.S. taxing authorities | $ | (15) | $ | (11) | $ | (4) |
Amounts accrued for interest and penalties associated with unrecognized income tax benefits are included in income tax expense on the Consolidated Statements of Operations. We summarize the amounts accrued at December 31 on the Consolidated Balance Sheets for interest and penalties associated with unrecognized income tax benefits and the related expense in the table below.
| INTEREST AND PENALTIES ASSOCIATED WITH UNRECOGNIZED INCOME TAX BENEFITS |
| (Dollars in millions) |
| | Interest and penalties | | Accrued interest and penalties |
| | Years ended December 31, | | December 31, |
| | 2014 | 2013 | 2012 | | 2014 | 2013 |
| Sempra Energy Consolidated: | | | | | | | | | | | |
| Interest (income) expense | $ | (4) | $ | 1 | $ | ― | | $ | ― | $ | 4 |
| Penalties | | (3) | | ― | | ― | | | ― | | 3 |
| SDG&E: | | | | | | | | | | | |
| Interest (income) expense | $ | (1) | $ | ― | $ | ― | | $ | ― | $ | 1 |
| SoCalGas: | | | | | | | | | | | |
| Interest income | $ | ― | $ | (1) | $ | ― | | $ | ― | $ | ― |
Penalties accrued and expensed at SDG&E and SoCalGas in all periods presented were zero or negligible.
Sempra Energy is subject to U.S. federal income tax as well as to income tax of multiple state and non-U.S. jurisdictions. We remain subject to examination for U.S. federal tax years after 2010. We are subject to examination by major state tax jurisdictions for tax years after 2008. Certain major non-U.S. income tax returns for tax years 2008 through the present are open to examination.
In addition, we intend to file federal refund claims for the 2009 and 2010 tax years during the first half of 2015; however, no additional tax may be assessed by the Internal Revenue Service for pre-2011 tax years. We have also filed state refund claims for tax years back to 1998. The pre-2009 tax years for our major state tax jurisdictions are closed to new issues; therefore, no additional tax may be assessed by the taxing authorities for these tax years.
SDG&E and SoCalGas are subject to U.S. federal income tax as well as income tax of state jurisdictions. They remain subject to examination for U.S. federal tax years after 2010 and by major state tax jurisdictions for tax years after 2008.
NOTE 7. EMPLOYEE BENEFIT PLANS
We are required by applicable U.S. GAAP to:
| § | recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status in the statement of financial position; |
| § | measure a plan’s assets and its obligations that determine its funded status as of the end of the fiscal year (with limited exceptions); and |
| § | recognize changes in the funded status of pension and other postretirement benefit plans in the year in which the changes occur. Generally, those changes are reported in other comprehensive income and as a separate component of shareholders’ equity. |
The detailed information presented below covers the employee benefit plans of Sempra Energy and its principal subsidiaries.
Sempra Energy has funded and unfunded noncontributory traditional defined benefit and cash balance plans, including separate plans for SDG&E and SoCalGas, which collectively cover all eligible employees, including members of the Sempra Energy board of directors who were participants in a predecessor plan on or before June 1, 1998. Pension benefits under the traditional defined benefit plans are based on service and final average pay, while the cash balance plans provide benefits using a career average earnings methodology.
Chilquinta Energía has an unfunded contributory defined benefit plan covering all employees hired before October 1, 1981 and an unfunded noncontributory termination indemnity obligation covering all employees. The plans generally provide defined benefits to retirees based on date of hire, years of service and final average salary.
Sempra Energy also has other postretirement benefit plans (PBOP), including separate plans for SDG&E and SoCalGas, which collectively cover all domestic (except Willmut Gas) and certain foreign employees. The life insurance plans are both contributory and noncontributory, and the health care plans are contributory. Participants’ contributions are adjusted annually. Other postretirement benefits include medical benefits for retirees’ spouses.
Chilquinta Energía also has two noncontributory postretirement benefit plans which cover substantially all employees – a health care plan and an energy subsidy plan that provides for reduced energy rates. The health care plan includes benefits for retirees’ spouses and dependents.
Pension and other postretirement benefits costs and obligations are dependent on assumptions used in calculating such amounts. These assumptions include
| § | expected return on plan assets |
| § | health care cost trend rates |
| § | rate of compensation increases |
| § | termination and retirement rates |
| § | utilization of postretirement welfare benefits |
| § | payout elections (lump sum or annuity) |
| § | lump sum interest rates |
We review these assumptions on an annual basis prior to the beginning of each year and update them as appropriate. We consider current market conditions, including interest rates, in making these assumptions. New mortality table studies were released by the Society of Actuaries during 2014 that significantly increased life expectancy assumptions, and we have incorporated these new assumptions, adjusted for the Sempra Energy companies’ actual mortality experience, in our calculations. We use a December 31 measurement date for all of our plans.
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 $512 million and $506 million at December 31, 2014 and 2013, respectively.
PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Benefit Plan Amendments Affecting 2014
During 2014, executive participants in a company nonqualified plan became eligible in this same plan for Supplemental Executive Retirement Plan benefits. Consistent with past practice, this was treated as a plan amendment and increased the recorded pension liability by $4 million at Sempra Energy Consolidated.
Effective January 1, 2014, a new high deductible medical benefit was provided to all SDG&E and SoCalGas retirees under the age of 65, except the represented retirees at SoCalGas, participating in the companies’ PBOP plans. This benefit replaced a previous benefit provided by the SDG&E plans and was an added benefit in the SoCalGas plan. These changes resulted in an increase of other postretirement benefit obligations by a negligible amount at SDG&E and by $1 million at each of Sempra Energy Consolidated and SoCalGas.
Benefit Plan Amendments Affecting 2013
The plan amendments below were adopted in 2013, and are therefore reflected in the 2013 pension and other postretirement benefit obligations.
Effective July 1, 2014, an enhanced pension benefit is provided to certain employees of SoCalGas who transfer from a represented to a nonrepresented position after June 30, 1998. This increased the pension benefit obligation by $27 million at each of Sempra Energy Consolidated and SoCalGas.
Effective April 1, 2014, we provided a one-time, ad hoc cost of living adjustment of 13.2 percent for SoCalGas and PE retirees who retired prior to July 1, 1996 and their beneficiaries that are receiving qualified pension benefits in the form of an annuity. This election increased the pension benefit obligation by $40 million at Sempra Energy Consolidated and $39 million at SoCalGas.
Effective January 1, 2013, the face value of the fully paid life insurance benefit for employees that participate in our Executive Retirement Life Insurance Program and retire after December 31, 2012 was increased from one times pay to one-and-a-half times pay. In addition, the tax gross-ups paid to the retiring employee based on the value of the final premium were eliminated. These changes resulted in a decrease of the other postretirement benefit obligation of $4 million at Sempra Energy Consolidated.
Effective January 1, 2014, the benefits provided by one of the dental plans available to all employees that participate in the plans, except the represented employees at SoCalGas, were enhanced to increase the annual total maximum and lifetime orthodontic maximum covered costs. In addition, the costs of diagnostic and preventive services were excluded from the total covered annual maximum costs. These plan design changes increased the recorded liability for other postretirement benefits by $1 million at each of Sempra Energy Consolidated and SoCalGas.
Special Termination Benefits Affecting 2014 and 2013
At SDG&E in 2014, and at both SDG&E and SoCalGas in 2013, all nonrepresented employees age 62 with 5 years of service and all other nonrepresented employees age 55 with 10 years of service that retired under the Voluntary Retirement Enhancement Program (VREP) offered in those years received an additional postretirement health benefit in the form of a $50,000 Health Reimbursement Account (HRA). In accordance with U.S. GAAP, we elected to treat the benefit obligation attributable to the HRA as special termination benefits. This resulted in increases to the recorded liability for other postretirement benefits of approximately $5 million for each of Sempra Energy Consolidated and SDG&E in 2014, and $5 million for Sempra Energy Consolidated and $2 million for each of SDG&E and SoCalGas in 2013.
Benefit Obligations and Assets
The following three tables provide a reconciliation of the changes in the plans’ projected benefit obligations and the fair value of assets during 2014 and 2013, and a statement of the funded status at December 31, 2014 and 2013:
| PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS |
| SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | | 2014 | 2013 |
| CHANGE IN PROJECTED BENEFIT OBLIGATION | | | | | | | | | |
| Net obligation at January 1 | $ | 3,459 | $ | 3,804 | | $ | 973 | $ | 1,115 |
| Service cost | | 101 | | 109 | | | 24 | | 28 |
| Interest cost | | 161 | | 148 | | | 49 | | 44 |
| Contributions from plan participants | | ― | | ― | | | 17 | | 16 |
| Actuarial loss (gain) | | 441 | | (371) | | | 105 | | (177) |
| Benefit payments | | (217) | | (293) | | | (58) | | (55) |
| Plan amendments | | 4 | | 67 | | | 1 | | (3) |
| Special termination benefits | | ― | | ― | | | 5 | | 5 |
| Settlements and curtailments | | (110) | | (5) | | | (1) | | ― |
| Net obligation at December 31 | | 3,839 | | 3,459 | | | 1,115 | | 973 |
| | | | | | | | | | |
| CHANGE IN PLAN ASSETS | | | | | | | | | |
| Fair value of plan assets at January 1 | | 2,789 | | 2,558 | | | 1,012 | | 873 |
| Actual return on plan assets | | 217 | | 396 | | | 67 | | 151 |
| Employer contributions | | 128 | | 133 | | | 16 | | 27 |
| Contributions from plan participants | | ― | | ― | | | 17 | | 16 |
| Benefit payments | | (217) | | (293) | | | (58) | | (55) |
| Settlements | | (110) | | (5) | | | ― | | ― |
| Fair value of plan assets at December 31 | | 2,807 | | 2,789 | | | 1,054 | | 1,012 |
| Funded status at December 31 | $ | (1,032) | $ | (670) | | $ | (61) | $ | 39 |
| Net recorded (liability) asset at December 31 | $ | (1,032) | $ | (670) | | $ | (61) | $ | 39 |
| PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | | 2014 | 2013 |
| CHANGE IN PROJECTED BENEFIT OBLIGATION | | | | | | | | | |
| Net obligation at January 1 | $ | 939 | $ | 1,067 | | $ | 171 | $ | 185 |
| Service cost | | 30 | | 32 | | | 7 | | 8 |
| Interest cost | | 43 | | 41 | | | 9 | | 8 |
| Contributions from plan participants | | ― | | ― | | | 6 | | 6 |
| Actuarial loss (gain) | | 101 | | (66) | | | 15 | | (19) |
| Benefit payments | | (25) | | (89) | | | (13) | | (12) |
| Special termination benefits | | ― | | ― | | | 5 | | 2 |
| Settlements | | (87) | | (4) | | | ― | | ― |
| Transfer of liability from (to) other plans | | 10 | | (42) | | | ― | | (7) |
| Net obligation at December 31 | | 1,011 | | 939 | | | 200 | | 171 |
| | | | | | | | | | |
| CHANGE IN PLAN ASSETS | | | | | | | | | |
| Fair value of plan assets at January 1 | | 819 | | 781 | | | 146 | | 126 |
| Actual return on plan assets | | 63 | | 117 | | | 11 | | 18 |
| Employer contributions | | 56 | | 51 | | | 14 | | 14 |
| Contributions from plan participants | | ― | | ― | | | 6 | | 6 |
| Benefit payments | | (25) | | (89) | | | (13) | | (12) |
| Settlements | | (87) | | (4) | | | ― | | ― |
| Transfer of assets from (to) other plans | | 2 | | (37) | | | ― | | (6) |
| Fair value of plan assets at December 31 | | 828 | | 819 | | | 164 | | 146 |
| Funded status at December 31 | $ | (183) | $ | (120) | | $ | (36) | $ | (25) |
| Net recorded liability at December 31 | $ | (183) | $ | (120) | | $ | (36) | $ | (25) |
| PROJECTED BENEFIT OBLIGATION, FAIR VALUE OF ASSETS AND FUNDED STATUS |
| SOUTHERN CALIFORNIA GAS COMPANY |
| (Dollars in millions) |
| | | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | | 2014 | 2013 |
| CHANGE IN PROJECTED BENEFIT OBLIGATION | | | | | | | | | |
| Net obligation at January 1 | $ | 2,110 | $ | 2,299 | | $ | 753 | $ | 873 |
| Service cost | | 60 | | 67 | | | 16 | | 17 |
| Interest cost | | 100 | | 90 | | | 38 | | 34 |
| Contributions from plan participants | | ― | | ― | | | 11 | | 10 |
| Actuarial loss (gain) | | 300 | | (285) | | | 90 | | (151) |
| Benefit payments | | (163) | | (169) | | | (43) | | (40) |
| Plan amendments | | ― | | 66 | | | 1 | | 1 |
| Special termination benefits | | ― | | ― | | | ― | | 2 |
| Settlements | | (10) | | ― | | | ― | | ― |
| Transfer of liability from other plans | | 1 | | 42 | | | ― | | 7 |
| Net obligation at December 31 | | 2,398 | | 2,110 | | | 866 | | 753 |
| | | | | | | | | | |
| CHANGE IN PLAN ASSETS | | | | | | | | | |
| Fair value of plan assets at January 1 | | 1,758 | | 1,581 | | | 848 | | 732 |
| Actual return on plan assets | | 138 | | 250 | | | 54 | | 131 |
| Employer contributions | | 39 | | 59 | | | ― | | 9 |
| Contributions from plan participants | | ― | | ― | | | 11 | | 10 |
| Benefit payments | | (163) | | (169) | | | (43) | | (40) |
| Settlements | | (10) | | ― | | | ― | | ― |
| Transfer of assets from other plans | | 1 | | 37 | | | ― | | 6 |
| Fair value of plan assets at December 31 | | 1,763 | | 1,758 | | | 870 | | 848 |
| Funded status at December 31 | $ | (635) | $ | (352) | | $ | 4 | $ | 95 |
| Net recorded (liability) asset at December 31 | $ | (635) | $ | (352) | | $ | 4 | $ | 95 |
For Sempra Energy Consolidated, SDG&E and SoCalGas, the actuarial losses for pension plans in 2014 were primarily due to a decrease in the weighted average discount rates and updated mortality rates (discussed above), and to a lesser extent at SoCalGas, a change in the rate used to convert annuity benefits to lump sums. The actuarial losses were partially offset at Sempra Energy Consolidated and SoCalGas by the impact of updated census data for SoCalGas and partially offset at all companies by a decrease in the cash balance interest crediting rate.
The actuarial losses for other postretirement plans in 2014 were primarily due to a decrease in the weighted average discount rates and updated mortality rates for all companies, and to lesser extent, updated census data for SDG&E and SoCalGas. The actuarial losses were partially offset by a decrease in anticipated retiree and spousal participation rates for all companies.
The actuarial gains for pension plans in 2013 were primarily due to an increase in the weighted average discount rate and the rate used to convert monthly annuity-type benefits to a lump sum benefit payment.
The actuarial gains for other postretirement plans in 2013 resulted from several factors, including an increase in the discount rate, updated census data and actual claims costs at SoCalGas, updates in actual premiums and retiree contributions for 2013, expected decrease in 2014 claims costs based on 2014 renewal premium rates, and a decrease in the healthcare cost trending rate. The actuarial gains were partially offset by the impact of updated census data and actual claims costs at all companies except SoCalGas, changes in retirement and termination rates, and an expected increase in non-spouse dependents for all employees of SoCalGas not covered by the defined dollar benefit.
Net Assets and Liabilities
The assets and liabilities of the pension and other postretirement benefit plans are affected by changing market conditions as well as when actual plan experience is different than assumed. Such events result in investment gains and losses, which we defer and recognize in pension and other postretirement benefit costs over a period of years. Sempra Energy Consolidated (except for SDG&E) and SoCalGas use the asset smoothing method for their pension and other postretirement plans. This method develops an asset value that recognizes realized and unrealized investment gains and losses over a three-year period. This adjusted asset value, known as the market-related value of assets, is used in conjunction with an expected long-term rate of return to determine the expected return-on-assets component of net periodic cost. SDG&E does not use the asset smoothing method, but rather recognizes realized and unrealized investment gains and losses during the current year.
The 10-percent corridor accounting method is used at Sempra Energy Consolidated, SDG&E and SoCalGas. Under the corridor accounting method, if as of the beginning of a year unrecognized net gain or loss exceeds 10 percent of the greater of the projected benefit obligation or the market-related value of plan assets, the excess is amortized over the average remaining service period of active participants. The asset smoothing and 10-percent corridor accounting methods help mitigate volatility of net periodic costs from year to year.
We recognize the overfunded or underfunded status of defined benefit pension and other postretirement plans as assets or liabilities, respectively; unrecognized changes in these assets and/or liabilities are normally recorded in Accumulated Other Comprehensive Income (Loss) on the balance sheet. The California Utilities and Mobile Gas record regulatory assets and liabilities that offset the funded pension and other postretirement plans’ assets or liabilities, as these costs are expected to be recovered in future utility rates based on agreements with regulatory agencies. At Willmut Gas, pension contributions are recovered in rates on a prospective basis, but are not recorded as a regulatory asset pending recovery.
The California Utilities record annual pension and other postretirement net periodic benefit costs equal to the contributions to their plans as authorized by the CPUC. The annual contributions to the pension plans are limited to a minimum required funding amount as determined by the Internal Revenue Service. The annual contributions to the other postretirement plans are equal to the lesser of the maximum tax deductible amount or the net periodic cost calculated in accordance with U.S. GAAP for pension and other postretirement benefit plans. Mobile Gas records annual pension and other postretirement net periodic benefit costs based on an estimate of the net periodic cost at the beginning of the year calculated in accordance with U.S. GAAP for pension and other postretirement benefit plans, as authorized by the Alabama Public Service Commission. Any differences between booked net periodic benefit cost and amounts contributed to the pension and other postretirement plans for the California Utilities are disclosed as regulatory adjustments in accordance with U.S. GAAP for regulated entities.
The net (liability) asset is included in the following categories on the Consolidated Balance Sheets at December 31:
| PENSION AND OTHER POSTRETIREMENT BENEFIT OBLIGATIONS, NET OF PLAN ASSETS AT DECEMBER 31 |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | | 2014 | 2013 |
| Sempra Energy Consolidated: | | | | | | | | | |
| Noncurrent assets | $ | ― | $ | ― | | $ | 4 | $ | 95 |
| Current liabilities | | (33) | | (59) | | | ― | | ― |
| Noncurrent liabilities | | (999) | | (611) | | | (65) | | (56) |
| Net recorded (liability) asset | $ | (1,032) | $ | (670) | | $ | (61) | $ | 39 |
| SDG&E: | | | | | | | | | |
| Current liabilities | $ | (3) | $ | (13) | | $ | ― | $ | ― |
| Noncurrent liabilities | | (180) | | (107) | | | (36) | | (25) |
| Net recorded liability | $ | (183) | $ | (120) | | $ | (36) | $ | (25) |
| SoCalGas: | | | | | | | | | |
| Noncurrent assets | $ | ― | $ | ― | | $ | 4 | $ | 95 |
| Current liabilities | | (2) | | (13) | | | ― | | ― |
| Noncurrent liabilities | | (633) | | (339) | | | ― | | ― |
| Net recorded (liability) asset | $ | (635) | $ | (352) | | $ | 4 | $ | 95 |
Amounts recorded in Accumulated Other Comprehensive Income (Loss) at December 31, 2014 and 2013, net of income tax effects and amounts recorded as regulatory assets, are as follows:
| AMOUNTS IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | | 2014 | 2013 |
| Sempra Energy Consolidated: | | | | | | | | | |
| Net actuarial loss | $ | (82) | $ | (73) | | $ | (1) | $ | ― |
| Prior service credit | | (2) | | ― | | | ― | | ― |
| Total | $ | (84) | $ | (73) | | $ | (1) | $ | ― |
| SDG&E: | | | | | | | | | |
| Net actuarial loss | $ | (13) | $ | (10) | | | | | |
| Prior service credit | | 1 | | 1 | | | | | |
| Total | $ | (12) | $ | (9) | | | | | |
| SoCalGas: | | | | | | | | | |
| Net actuarial loss | $ | (5) | $ | (5) | | | | | |
| Prior service credit | | 1 | | 1 | | | | | |
| Total | $ | (4) | $ | (4) | | | | | |
The accumulated benefit obligation for defined benefit pension plans at December 31, 2014 and 2013 was as follows:
| ACCUMULATED BENEFIT OBLIGATION |
| (Dollars in millions) |
| | Sempra Energy Consolidated | | SDG&E | | SoCalGas |
| | 2014 | 2013 | | 2014 | 2013 | | 2014 | 2013 |
| Accumulated benefit obligation | $ | 3,555 | $ | 3,254 | | $ | 978 | $ | 923 | | $ | 2,182 | $ | 1,944 |
Sempra Energy has unfunded and funded pension plans. SDG&E and SoCalGas each have an unfunded and a funded pension plan. The following table shows the obligations of funded pension plans with benefit obligations in excess of plan assets at December 31:
| OBLIGATIONS OF FUNDED PENSION PLANS |
| (Dollars in millions) |
| | 2014 | 2013 |
| Sempra Energy Consolidated: | | | | |
| Projected benefit obligation | $ | 3,592 | $ | 3,212 |
| Accumulated benefit obligation | | 3,343 | | 3,027 |
| Fair value of plan assets | | 2,807 | | 2,789 |
| SDG&E: | | | | |
| Projected benefit obligation | $ | 964 | $ | 899 |
| Accumulated benefit obligation | | 937 | | 886 |
| Fair value of plan assets | | 828 | | 819 |
| SoCalGas: | | | | |
| Projected benefit obligation | $ | 2,379 | $ | 2,085 |
| Accumulated benefit obligation | | 2,166 | | 1,920 |
| Fair value of plan assets | | 1,763 | | 1,758 |
Net Periodic Benefit Cost, 2012-2014
The following three tables provide the components of net periodic benefit cost and amounts recognized in other comprehensive income for the years ended December 31:
| NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME |
| SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 |
| NET PERIODIC BENEFIT COST | | | | | | | | | | | | | |
| Service cost | $ | 101 | $ | 109 | $ | 90 | | $ | 24 | $ | 28 | $ | 25 |
| Interest cost | | 161 | | 148 | | 162 | | | 49 | | 44 | | 52 |
| Expected return on assets | | (171) | | (162) | | (155) | | | (63) | | (58) | | (53) |
| Amortization of: | | | | | | | | | | | | | |
| Prior service cost (credit) | | 11 | | 4 | | 3 | | | (5) | | (4) | | (4) |
| Actuarial loss | | 18 | | 54 | | 47 | | | ― | | 7 | | 12 |
| Settlement and curtailment charges | | 31 | | 2 | | 8 | | | (1) | | ― | | ― |
| Special termination benefits | | ― | | ― | | ― | | | 5 | | 5 | | ― |
| Regulatory adjustment | | (31) | | (20) | | (29) | | | 6 | | 6 | | 7 |
| Total net periodic benefit cost | | 120 | | 135 | | 126 | | | 15 | | 28 | | 39 |
| | | | | | | | | | | | | | |
| CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS | | | | | | | | | | | | | |
| RECOGNIZED IN OTHER COMPREHENSIVE INCOME | | | | | | | | | | | | | |
| Net loss (gain) | | 38 | | (30) | | 19 | | | 1 | | (8) | | (6) |
| Prior service cost | | 4 | | 1 | | ― | | | ― | | ― | | ― |
| Amortization of actuarial loss | | (23) | | (9) | | (9) | | | ― | | (1) | | ― |
| Total recognized in other comprehensive income | | 19 | | (38) | | 10 | | | 1 | | (9) | | (6) |
Total recognized in net periodic benefit cost and other comprehensive income | $ | 139 | $ | 97 | $ | 136 | | $ | 16 | $ | 19 | $ | 33 |
| NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME |
| SAN DIEGO GAS & ELECTRIC COMPANY |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 |
| NET PERIODIC BENEFIT COST | | | | | | | | | | | | | |
| Service cost | $ | 30 | $ | 32 | $ | 28 | | $ | 7 | $ | 8 | $ | 7 |
| Interest cost | | 43 | | 41 | | 45 | | | 9 | | 8 | | 9 |
| Expected return on assets | | (55) | | (52) | | (47) | | | (10) | | (8) | | (8) |
| Amortization of: | | | | | | | | | | | | | |
| Prior service cost | | 2 | | 2 | | 2 | | | 2 | | 4 | | 4 |
| Actuarial loss | | 4 | | 14 | | 14 | | | ― | | ― | | ― |
| Settlement charge | | 19 | | 1 | | 1 | | | ― | | ― | | ― |
| Special termination benefits | | ― | | ― | | ― | | | 5 | | 2 | | ― |
| Regulatory adjustment | | 12 | | 14 | | 6 | | | 1 | | ― | | 1 |
| Total net periodic benefit cost | | 55 | | 52 | | 49 | | | 14 | | 14 | | 13 |
| | | | | | | | | | | | | | |
| CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS | | | | | | | | | | | | | |
| RECOGNIZED IN OTHER COMPREHENSIVE INCOME | | | | | | | | | | | | | |
| Net loss (gain) | | 8 | | (2) | | 2 | | | ― | | ― | | ― |
| Amortization of actuarial loss | | (3) | | (1) | | (1) | | | ― | | ― | | ― |
| Total recognized in other comprehensive income | | 5 | | (3) | | 1 | | | ― | | ― | | ― |
Total recognized in net periodic benefit cost and other comprehensive income | $ | 60 | $ | 49 | $ | 50 | | $ | 14 | $ | 14 | $ | 13 |
| NET PERIODIC BENEFIT COST AND AMOUNTS RECOGNIZED IN OTHER COMPREHENSIVE INCOME |
| SOUTHERN CALIFORNIA GAS COMPANY |
| (Dollars in millions) |
| | Pension benefits | | Other postretirement benefits |
| | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 |
| NET PERIODIC BENEFIT COST | | | | | | | | | | | | | |
| Service cost | $ | 60 | $ | 67 | $ | 53 | | $ | 16 | $ | 17 | $ | 16 |
| Interest cost | | 100 | | 90 | | 99 | | | 38 | | 34 | | 41 |
| Expected return on assets | | (104) | | (98) | | (96) | | | (51) | | (48) | | (44) |
| Amortization of: | | | | | | | | | | | | | |
| Prior service cost (credit) | | 9 | | 2 | | 2 | | | (8) | | (8) | | (7) |
| Actuarial loss | | 6 | | 31 | | 23 | | | ― | | 6 | | 11 |
| Settlement charge | | 4 | | ― | | 1 | | | ― | | ― | | ― |
| Special termination benefits | | ― | | ― | | ― | | | ― | | 2 | | ― |
| Regulatory adjustment | | (43) | | (34) | | (36) | | | 5 | | 6 | | 5 |
| Total net periodic benefit cost | | 32 | | 58 | | 46 | | | ― | | 9 | | 22 |
| | | | | | | | | | | | | | |
| CHANGES IN PLAN ASSETS AND BENEFIT OBLIGATIONS | | | | | | | | | | | | | |
| RECOGNIZED IN OTHER COMPREHENSIVE INCOME | | | | | | | | | | | | | |
| Net loss (gain) | | 5 | | 3 | | (4) | | | ― | | ― | | ― |
| Amortization of actuarial loss | | (5) | | (1) | | (1) | | | ― | | ― | | ― |
| Total recognized in other comprehensive income | | ― | | 2 | | (5) | | | ― | | ― | | ― |
Total recognized in net periodic benefit cost and other comprehensive income | $ | 32 | $ | 60 | $ | 41 | | $ | ― | $ | 9 | $ | 22 |
| | | | | | | | | | | | | | |
The estimated net loss for the pension plans that will be amortized from Accumulated Other Comprehensive Income (Loss) into net periodic benefit cost in 2015 is $9 million for Sempra Energy Consolidated, $1 million for SDG&E and $1 million for SoCalGas. Negligible amounts of prior service credit for the pension plans will be similarly amortized in 2015.
Assumptions for Pension and Other Postretirement Benefit Plans
Benefit Obligation and Net Periodic Benefit Cost
Except for the Chilquinta Energía plans, we develop the discount rate assumptions based on the results of a third party modeling tool that develops the discount rate by matching each plan’s expected cash flows to interest rates and expected maturity values of individually selected bonds in a hypothetical portfolio. The model controls the level of accumulated surplus that may result from the selection of bonds based solely on their premium yields by limiting the number of years to look back for selection to 3 years for pre-30-year and 6 years for post-30-year benefit payments. Additionally, the model ensures that an adequate number of bonds are selected in the portfolio by limiting the amount of the plan’s benefit payments that can be met by a single bond to 7.5 percent.
We selected individual bonds from a universe of Bloomberg AA-rated bonds which:
| § | have an outstanding issue of at least $50 million; |
| § | are non-callable (or callable with make-whole provisions); |
| § | exclude collateralized bonds; and |
| § | exclude the top and bottom 10 percent of yields to avoid relying on bonds which might be mispriced or misgraded. |
This selection methodology also mitigates the impact of market volatility on the portfolio by excluding bonds with the following characteristics:
| § | The issuer is on review for downgrade by a major rating agency if the downgrade would eliminate the issuer from the portfolio. |
| § | Recent events have caused significant price volatility to which rating agencies have not reacted. |
| § | Lack of liquidity is causing price quotes to vary significantly from broker to broker. |
We believe that this bond selection approach provides the best estimate of discount rates to estimate settlement values for our plans’ benefit obligations as required by applicable U.S. GAAP.
We develop the discount rate assumptions for the plans at Chilquinta Energía based on 10-year Chilean government bond yields and the expected local long-term rate of inflation. This method for developing the discount rate is required when there is no deep market for high quality corporate bonds.
Long-term return on assets is based on the weighted-average of the plans’ investment allocation as of the measurement date and the expected returns for those asset types.
The significant assumptions affecting benefit obligation and net periodic benefit cost are as follows:
| WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE BENEFIT OBLIGATION AT DECEMBER 31 |
| |
| | | Pension benefits | | Other postretirement benefits |
| | | 2014 | 2013 | | 2014 | 2013 |
| Sempra Energy Consolidated: | | | | | | | | | |
| Discount rate | 4.09 | % | 4.84 | % | | 4.15 | % | 4.95 | % |
| Rate of compensation increase | 3.50-10.00 | | 3.50-10.00 | | | 3.50-10.00 | | 3.50-10.00 | |
| SDG&E: | | | | | | | | | |
| Discount rate | 4.00 | % | 4.69 | % | | 4.15 | % | 5.00 | % |
| Rate of compensation increase | 3.50-10.00 | | 3.50-10.00 | | | 3.50-10.00 | | 3.50-10.00 | |
| SoCalGas: | | | | | | | | | |
| Discount rate | 4.15 | % | 4.94 | % | | 4.15 | % | 4.95 | % |
| Rate of compensation increase | 3.50-10.00 | | 3.50-10.00 | | | 3.50-10.00 | | 3.50-10.00 | |
| WEIGHTED-AVERAGE ASSUMPTIONS USED TO DETERMINE NET PERIODIC BENEFIT COST FOR YEARS ENDED DECEMBER 31 |
| |
| | | Pension benefits | | Other postretirement benefits |
| | | 2014 | 2013 | 2012 | | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | | | | | | | | |
| Discount rate | 4.85 | % | 4.04 | % | 4.40-5.05 | % | | 4.95 | % | 4.09 | % | 4.10-5.15 | % |
| Expected return on plan assets | 7.00 | | 7.00 | | 7.00 | | | 6.97 | | 6.96 | | 6.96 | |
| Rate of compensation increase | 3.50-10.00 | | 3.50-9.50 | | 3.50-8.50 | | | 3.50-10.00 | | 3.50-9.50 | | 3.50-9.50 | |
| SDG&E: | | | | | | | | | | | | | |
| Discount rate | 4.69 | % | 3.94 | % | 4.70-4.80 | % | | 5.00 | % | 4.10 | % | 5.05 | % |
| Expected return on plan assets | 7.00 | | 7.00 | | 7.00 | | | 6.88 | | 6.81 | | 6.81 | |
| Rate of compensation increase | 3.50-10.00 | | 3.50-9.50 | | 3.50-8.50 | | | 3.50-10.00 | | N/A | | N/A | |
| SoCalGas: | | | | | | | | | | | | | |
| Discount rate | 4.94 | % | 4.10 | % | 4.70-5.05 | % | | 4.95 | % | 4.10 | % | 5.15 | % |
| Expected return on plan assets | 7.00 | | 7.00 | | 7.00 | | | 7.00 | | 7.00 | | 7.00 | |
| Rate of compensation increase | 3.50-10.00 | | 3.50-9.50 | | 3.50-8.50 | | | 3.50-10.00 | | 3.50-9.50 | | 3.50-9.50 | |
Health Care Cost Trend Rates
Assumed health care cost trend rates have a significant effect on the amounts that we report for the health care plan costs. Following are the health care cost trend rates applicable to our postretirement benefit plans:
| ASSUMED HEALTH CARE COST TREND RATES AT DECEMBER 31 |
| |
| | | Other postretirement benefit plans(1) |
| | | Pre-65 retirees | | Retirees aged 65 years and older |
| | | 2014 | | 2013 | | 2012 | | | 2014 | | 2013 | | 2012 | |
| Health care cost trend rate assumed for next year | 7.75 | % | 8.25 | % | 10.00 | % | | 5.25 | % | 5.50 | % | 8.25 | % |
Rate to which the cost trend rate is assumed to decline (the ultimate trend) | 5.00 | % | 5.00 | % | 5.00 | % | | 4.50 | % | 4.50 | % | 4.75 | % |
| Year the rate reaches the ultimate trend | 2020 | | 2020 | | 2020 | | | 2020 | | 2020 | | 2020 | |
| (1) | Excludes Mobile Gas Plan. For Mobile Gas, the health care cost trend rate assumed for next year for all retirees was 7.75 percent, 7.50 percent and 8.00 percent in 2014, 2013 and 2012, respectively; the ultimate trend was 5.00 percent in 2014, 2013 and 2012; and the year the rate reaches the ultimate trend was 2020, 2019 and 2020 in 2014, 2013 and 2012, respectively. |
A one-percent change in assumed health care cost trend rates would have had the following effects in 2014:
| EFFECT OF ONE-PERCENT CHANGE IN ASSUMED HEALTH CARE COST TREND RATES |
| (Dollars in millions) |
| | Sempra Energy | | | | |
| | Consolidated | | SDG&E | | SoCalGas |
| | 1% | 1% | | 1% | 1% | | 1% | 1% |
| | Increase | Decrease | | Increase | Decrease | | Increase | Decrease |
| Effect on total of service and interest | | | | | | | | | | | | | | |
| cost components of net periodic | | | | | | | | | | | | | | |
| postretirement health care benefit cost | $ | 7 | $ | (5) | | $ | 1 | $ | (1) | | $ | 5 | $ | (4) |
| Effect on the health care component of the | | | | | | | | | | | | | | |
| accumulated other postretirement | | | | | | | | | | | | | | |
| benefit obligations | | 86 | | (75) | | | 9 | | (7) | | | 74 | | (65) |
Investment Allocation Strategy for Sempra Energy’s Pension Master Trust
Sempra Energy’s pension master trust holds the investments for the pension and other postretirement benefit plans. We maintain additional trusts as we discuss below for certain of the California Utilities’ other postretirement benefit plans. Other than through indexing strategies, the trusts do not invest in securities of Sempra Energy.
The current asset allocation objective for the pension master trust is to protect the funded status of the plans while generating sufficient returns to cover future benefit payments and accruals. We assess the portfolio performance by comparing actual returns with relevant benchmarks. Currently, the pension plans’ asset allocations are
§ | 38 percent domestic equity |
| § | 26 percent international equity |
| § | 5 percent global high yield credit |
| § | 4 percent long government |
The asset allocation of the plans is reviewed by our Plan Funding Committee and our Pension and Benefits Investment Committee (the Committees) on a regular basis. When evaluating strategic asset allocations, the Committees consider many variables, including:
| § | variability and level of contributions |
| § | a range of expected outcomes over varying confidence levels |
We maintain allocations at strategic levels with reasonable bands of variance. When asset class exposure reaches a minimum or maximum level, we generally rebalance the portfolio back to target allocations.
In accordance with the Sempra Energy pension investment guidelines, derivative financial instruments may be used by the pension master trust’s equity and fixed income portfolio investment managers to equitize cash, hedge certain exposures, and as substitutes for certain types of fixed income securities.
Rate of Return Assumption
The expected return on assets in our pension plans and other postretirement benefit plans is based on the weighted-average of the plans’ investment allocations to specific asset classes as of the measurement date. We arrive at a 7 percent expected return on assets by considering both the historical and forecasted long-term rates of return on those asset classes. We expect a return of between 7 percent and 9 percent on return-seeking assets and between 3 percent and 5 percent for risk-mitigating assets. Certain trusts that hold assets for the SDG&E and Mobile Gas other postretirement benefit plans are subject to taxation, which impacts the expected after-tax return on assets in these plans.
Concentration of Risk
Plan assets are fully diversified across global equity and bond markets, and other than what is indicated by the target asset allocations, contain no concentration of risk in any one economic, industry, maturity or geographic sector.
Investment Strategy for SDG&E’s and SoCalGas’ Other Postretirement Benefit Plans
SDG&E’s and SoCalGas’ other postretirement benefit plans are funded by cash contributions from SDG&E and SoCalGas and their current retirees. The assets of these plans are placed into the pension master trust and other Voluntary Employee Beneficiary Association (VEBA) trusts. The assets in the VEBA trusts are invested at an allocation similar to the pension master trust, with 70 percent invested in return-seeking and 30 percent invested in risk-mitigating assets. This allocation has been formulated to best suit the long-term nature of the obligations.
Fair Value of Pension and Other Postretirement Benefit Plan Assets
We classify the investments in Sempra Energy’s pension master trust and the trusts for the California Utilities’ other postretirement benefit plans into:
| § | Level 1, for securities valued using quoted prices from active markets for identical assets; |
| § | Level 2, for securities not traded on an active market but for which observable market inputs are readily available; and |
| § | Level 3, for securities and investments valued based on significant unobservable inputs. Investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. |
The following are descriptions of the valuation methods and assumptions we use to estimate the fair values of investments held by pension and other postretirement benefit plan trusts.
Equity Securities — Equity securities are valued using quoted prices listed on nationally recognized securities exchanges.
Fixed Income Securities — Certain fixed income securities are valued at the closing price reported in the active market in which the security is traded. Other fixed income securities are valued based on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar securities, the security is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks. Certain high yield fixed-income securities are valued by applying a price adjustment to the bid side to calculate a mean and ask value. Adjustments can vary based on maturity, credit standing, and reported trade frequencies. The bid to ask spread is determined by the investment manager based on the review of the available market information.
Registered Investment Companies — Investments in mutual funds sponsored by a registered investment company are valued based on exchange listed prices for equity and certain fixed income securities or are valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks for the remaining fixed income securities.
Common/Collective Trusts — Investments in common/collective trust funds are valued based on the redemption price of units owned, which is based on the current fair value of the funds’ underlying assets.
Private Equity Funds — Investments in private equity funds do not trade in active markets. Fair value is determined by the fund managers, based upon their review of the underlying investments as well as their utilization of discounted cash flows and other valuation models.
Venture Capital Funds — These funds consist of investments in private equities that are held by limited partnerships following various strategies, including venture capital and corporate finance. The partnerships generally have limited lives of 10 years, after which liquidating distributions will be received. Fair value is determined by attributing a proportionate share of net assets to an ownership interest in partners’ capital.
Real Estate Funds — Investments in real estate funds are valued based on the net asset value per share. Net asset value is based on the fair value of the underlying investments.
Derivative Financial Instruments — Forward currency contracts are valued at the prevailing forward exchange rate of the underlying currencies, and unrealized gain (loss) is recorded daily. Fixed income futures and options are marked to market daily. Equity index future contracts are valued at the last sales price quoted on the exchange on which they primarily trade.
The methods described are intended to produce a fair value calculation that is indicative of net realizable value or reflective of future fair values. However, while management believes the valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
We provide more discussion of fair value measurements in Notes 1 and 10. The following tables set forth by level within the fair value hierarchy a summary of the investments in our pension and other postretirement benefit plan trusts measured at fair value on a recurring basis.
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 the valuation techniques used in recurring fair value measurement.
The fair values of our pension plan assets by asset category are as follows:
| FAIR VALUE MEASUREMENTS — INVESTMENT ASSETS OF PENSION PLANS |
| (Dollars in millions) |
| | | Fair value at December 31, 2014 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| SDG&E: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | $ | 307 | $ | ― | $ | ― | $ | 307 |
| Foreign | | 186 | | ― | | ― | | 186 |
| Domestic preferred | | ― | | 1 | | ― | | 1 |
| Foreign preferred | | 1 | | ― | | ― | | 1 |
| Registered investment companies | | 40 | | ― | | ― | | 40 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 38 | | ― | | ― | | 38 |
| Domestic municipal bonds | | ― | | 11 | | ― | | 11 |
| Foreign government bonds | | ― | | 12 | | ― | | 12 |
| Domestic corporate bonds(2) | | ― | | 117 | | ― | | 117 |
| Foreign corporate bonds | | ― | | 36 | | ― | | 36 |
| Common/collective trusts(3) | | ― | | 62 | | ― | | 62 |
| Registered investment companies | | ― | | 10 | | ― | | 10 |
| Other investments(4) | | ― | | ― | | 4 | | 4 |
| Total investment assets(5) | | 572 | | 249 | | 4 | | 825 |
| | | | | | | | | | |
| SoCalGas: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 651 | | ― | | ― | | 651 |
| Foreign | | 395 | | ― | | ― | | 395 |
| Domestic preferred | | ― | | 3 | | ― | | 3 |
| Foreign preferred | | 3 | | 1 | | ― | | 4 |
| Registered investment companies | | 86 | | ― | | ― | | 86 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 80 | | ― | | ― | | 80 |
| Domestic municipal bonds | | ― | | 24 | | ― | | 24 |
| Foreign government bonds | | ― | | 25 | | ― | | 25 |
| Domestic corporate bonds(2) | | ― | | 249 | | ― | | 249 |
| Foreign corporate bonds | | ― | | 77 | | ― | | 77 |
| Common/collective trusts(3) | | ― | | 132 | | ― | | 132 |
| Registered investment companies | | ― | | 21 | | ― | | 21 |
| Other investments(4) | | 1 | | ― | | 8 | | 9 |
| Total investment assets(6) | | 1,216 | | 532 | | 8 | | 1,756 |
| | | | | | | | | | |
| Other Sempra Energy: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 81 | | ― | | ― | | 81 |
| Foreign | | 49 | | ― | | ― | | 49 |
| Foreign preferred | | ― | | 1 | | ― | | 1 |
| Registered investment companies | | 10 | | ― | | ― | | 10 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 9 | | ― | | ― | | 9 |
| Domestic municipal bonds | | ― | | 4 | | ― | | 4 |
| Foreign government bonds | | ― | | 3 | | ― | | 3 |
| Domestic corporate bonds(2) | | ― | | 30 | | ― | | 30 |
| Foreign corporate bonds | | ― | | 9 | | ― | | 9 |
| Common/collective trusts(3) | | ― | | 16 | | ― | | 16 |
| Registered investment companies | | ― | | 2 | | ― | | 2 |
| Other investments(4) | | ― | | ― | | 1 | | 1 |
| Total other Sempra Energy(7) | | 149 | | 65 | | 1 | | 215 |
| Total Sempra Energy Consolidated(8) | $ | 1,937 | $ | 846 | $ | 13 | $ | 2,796 |
| (1) | Investments in common stock of domestic corporations. |
| (2) | Bonds of U.S. issuers from diverse industries, primarily investment-grade. |
| (3) | Investments in common/collective trusts held in Sempra Energy’s Pension Master Trust. |
| (4) | Investments in venture capital and real estate funds, stated at net asset value, and derivative financial instruments. |
| (5) | Excludes cash and cash equivalents of $3 million at SDG&E. |
| (6) | Excludes cash and cash equivalents of $7 million at SoCalGas. |
| (7) | Excludes cash and cash equivalents of $1 million at Other Sempra Energy. |
| (8) | Excludes cash and cash equivalents of $11 million at Sempra Energy Consolidated. |
| FAIR VALUE MEASUREMENTS — INVESTMENT ASSETS OF PENSION PLANS |
| (Dollars in millions) |
| | | Fair value at December 31, 2013 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| SDG&E: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | $ | 317 | $ | ― | $ | ― | $ | 317 |
| Foreign | | 211 | | ― | | ― | | 211 |
| Foreign preferred | | 2 | | ― | | ― | | 2 |
| Registered investment companies | | 44 | | ― | | ― | | 44 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 2 | | ― | | ― | | 2 |
| Domestic municipal bonds | | ― | | 11 | | ― | | 11 |
| Foreign government bonds | | ― | | 25 | | ― | | 25 |
| Domestic corporate bonds(2) | | ― | | 152 | | ― | | 152 |
| Domestic partnership bonds(2) | | ― | | 1 | | ― | | 1 |
| Foreign corporate bonds | | ― | | 55 | | ― | | 55 |
| Common/collective trusts(3) | | ― | | 25 | | ― | | 25 |
| Other investments(4) | | ― | | ― | | 6 | | 6 |
| Total investment assets(5) | | 576 | | 269 | | 6 | | 851 |
| | | | | | | | | | |
| SoCalGas: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 637 | | ― | | ― | | 637 |
| Foreign | | 423 | | ― | | ― | | 423 |
| Foreign preferred | | 4 | | ― | | ― | | 4 |
| Registered investment companies | | 89 | | ― | | ― | | 89 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 4 | | ― | | ― | | 4 |
| Domestic municipal bonds | | ― | | 21 | | ― | | 21 |
| Foreign government bonds | | ― | | 51 | | ― | | 51 |
| Domestic corporate bonds(2) | | ― | | 306 | | ― | | 306 |
| Domestic partnership bonds(2) | | ― | | 2 | | ― | | 2 |
| Foreign corporate bonds | | ― | | 110 | | ― | | 110 |
| Common/collective trusts(3) | | ― | | 50 | | ― | | 50 |
| Other investments(4) | | ― | | ― | | 13 | | 13 |
| Total investment assets(6) | | 1,157 | | 540 | | 13 | | 1,710 |
| | | | | | | | | | |
| Other Sempra Energy: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 79 | | ― | | ― | | 79 |
| Foreign | | 52 | | ― | | ― | | 52 |
| Registered investment companies | | 11 | | ― | | ― | | 11 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 1 | | ― | | ― | | 1 |
| Domestic municipal bonds | | ― | | 3 | | ― | | 3 |
| Foreign government bonds | | ― | | 7 | | ― | | 7 |
| Domestic corporate bonds(2) | | ― | | 38 | | ― | | 38 |
| Foreign corporate bonds | | ― | | 13 | | ― | | 13 |
| Common/collective trusts(3) | | ― | | 5 | | ― | | 5 |
| Other investments(4) | | ― | | ― | | 2 | | 2 |
| Total other Sempra Energy(7) | | 143 | | 66 | | 2 | | 211 |
| Total Sempra Energy Consolidated(8) | $ | 1,876 | $ | 875 | $ | 21 | $ | 2,772 |
| (1) | Investments in common stock of domestic corporations. |
| (2) | Bonds of U.S. issuers from diverse industries, primarily investment-grade. |
| (3) | Investments in common/collective trusts held in Sempra Energy’s Pension Master Trust. |
| (4) | Investments in venture capital and real estate funds, stated at net asset value, and derivative financial instruments. |
| (5) | Excludes cash and cash equivalents of $5 million at SDG&E and transfers payable to other plans of $37 million. |
| (6) | Excludes cash and cash equivalents of $11 million at SoCalGas and transfers receivable from other plans of $37 million. |
| (7) | Excludes cash and cash equivalents of $1 million at Other Sempra Energy. |
| (8) | Excludes cash and cash equivalents of $17 million at Sempra Energy Consolidated. |
The fair values by asset category of the other postretirement benefit plan assets held in the pension master trust and in the additional trusts for SoCalGas’ other postretirement benefit plans and SDG&E’s other postretirement benefit plan (PBOP plan trusts) are as follows:
| FAIR VALUE MEASUREMENTS — INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS |
| (Dollars in millions) |
| | | Fair value at December 31, 2014 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| SDG&E: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | $ | 41 | $ | ― | $ | ― | $ | 41 |
| Foreign | | 25 | | ― | | ― | | 25 |
| Registered investment companies | | 43 | | ― | | ― | | 43 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 5 | | ― | | ― | | 5 |
| Domestic municipal bonds(2) | | ― | | 3 | | ― | | 3 |
| Domestic corporate bonds(3) | | ― | | 16 | | ― | | 16 |
| Foreign government bonds | | ― | | 2 | | ― | | 2 |
| Foreign corporate bonds | | ― | | 5 | | ― | | 5 |
| Common/collective trusts(4) | | ― | | 8 | | ― | | 8 |
| Registered investment companies | | ― | | 16 | | ― | | 16 |
| Total investment assets | | 114 | | 50 | | ― | | 164 |
| | | | | | | | | | |
| SoCalGas: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 133 | | ― | | ― | | 133 |
| Foreign | | 81 | | ― | | ― | | 81 |
| Domestic preferred | | ― | | 1 | | ― | | 1 |
| Foreign preferred | | 1 | | ― | | ― | | 1 |
| Registered investment companies | | 45 | | ― | | ― | | 45 |
| Broad market funds | | ― | | 222 | | ― | | 222 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 16 | | ― | | ― | | 16 |
| Domestic municipal bonds | | ― | | 5 | | ― | | 5 |
| Domestic corporate bonds(3) | | ― | | 61 | | ― | | 61 |
| Foreign government bonds | | ― | | 5 | | ― | | 5 |
| Foreign corporate bonds | | ― | | 25 | | ― | | 25 |
| Common/collective trusts(4) | | ― | | 265 | | ― | | 265 |
| Registered investment companies | | ― | | 6 | | ― | | 6 |
| Other investments(5) | | ― | | ― | | 2 | | 2 |
| Total investment assets(6) | | 276 | | 590 | | 2 | | 868 |
| | | | | | | | | | |
| Other Sempra Energy: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 6 | | ― | | ― | | 6 |
| Foreign | | 3 | | ― | | ― | | 3 |
| Registered investment companies | | 4 | | ― | | ― | | 4 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 1 | | ― | | ― | | 1 |
| Domestic corporate bonds(3) | | ― | | 2 | | ― | | 2 |
| Common/collective trusts(4) | | ― | | 1 | | ― | | 1 |
| Registered investment companies | | ― | | 2 | | ― | | 2 |
| Total other Sempra Energy(7) | | 14 | | 5 | | ― | | 19 |
| Total Sempra Energy Consolidated(8) | $ | 404 | $ | 645 | $ | 2 | $ | 1,051 |
| (1) | Investments in common stock of domestic corporations. |
| (2) | Bonds of California municipalities held in SDG&E PBOP plan trusts. |
| (3) | Bonds of U.S. issuers from diverse industries, primarily investment-grade. |
| (4) | Investment in common/collective trusts held in PBOP plan VEBA trusts. |
| (5) | Investments in venture capital and real estate funds, stated at net asset value, and derivative financial instruments. |
| (6) | Excludes cash and cash equivalents of $2 million held in SoCalGas PBOP plan trusts. |
| (7) | Excludes cash and cash equivalents of $1 million held in Other Sempra Energy PBOP plan trusts. |
| (8) | Excludes cash and cash equivalents of $3 million at Sempra Energy Consolidated. |
| FAIR VALUE MEASUREMENTS — INVESTMENT ASSETS OF OTHER POSTRETIREMENT BENEFIT PLANS |
| (Dollars in millions) |
| | | Fair value at December 31, 2013 |
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| SDG&E: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | $ | 37 | $ | ― | $ | ― | $ | 37 |
| Foreign | | 25 | | ― | | ― | | 25 |
| Registered investment companies | | 43 | | ― | | ― | | 43 |
| Fixed income securities: | | | | | | | | |
| Domestic municipal bonds(2) | | ― | | 3 | | ― | | 3 |
| Domestic corporate bonds(3) | | ― | | 18 | | ― | | 18 |
| Foreign government bonds | | ― | | 3 | | ― | | 3 |
| Foreign corporate bonds | | ― | | 6 | | ― | | 6 |
| Common/collective trusts(4) | | ― | | 3 | | ― | | 3 |
| Registered investment companies | | ― | | 12 | | ― | | 12 |
| Other investments(5) | | ― | | ― | | 1 | | 1 |
| Total investment assets(6) | | 105 | | 45 | | 1 | | 151 |
| | | | | | | | | | |
| SoCalGas: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 128 | | ― | | ― | | 128 |
| Foreign | | 83 | | ― | | ― | | 83 |
| Foreign preferred | | 1 | | ― | | ― | | 1 |
| Registered investment companies | | 43 | | ― | | ― | | 43 |
| Broad market funds | | ― | | 220 | | ― | | 220 |
| Fixed income securities: | | | | | | | | |
| U.S. Treasury securities | | 1 | | ― | | ― | | 1 |
| Domestic municipal bonds | | ― | | 4 | | ― | | 4 |
| Domestic corporate bonds(3) | | ― | | 60 | | ― | | 60 |
| Foreign government bonds | | ― | | 10 | | ― | | 10 |
| Foreign corporate bonds | | ― | | 22 | | ― | | 22 |
| Common/collective trusts(4) | | ― | | 262 | | ― | | 262 |
| Registered investment companies | | ― | | 3 | | ― | | 3 |
| Other investments(5) | | ― | | ― | | 2 | | 2 |
| Total investment assets(7) | | 256 | | 581 | | 2 | | 839 |
| | | | | | | | | | |
| Other Sempra Energy: | | | | | | | | |
| Equity securities: | | | | | | | | |
| Domestic(1) | | 4 | | ― | | ― | | 4 |
| Foreign | | 4 | | ― | | ― | | 4 |
| Registered investment companies | | 4 | | ― | | ― | | 4 |
| Fixed income securities: | | | | | | | | |
| Domestic corporate bonds(3) | | ― | | 3 | | ― | | 3 |
| Foreign government bonds | | ― | | 1 | | ― | | 1 |
| Foreign corporate bonds | | ― | | 1 | | ― | | 1 |
| Registered investment companies | | ― | | 1 | | ― | | 1 |
| Total other Sempra Energy | | 12 | | 6 | | ― | | 18 |
| Total Sempra Energy Consolidated(8) | $ | 373 | $ | 632 | $ | 3 | $ | 1,008 |
| (1) | Investments in common stock of domestic corporations. |
| (2) | Bonds of California municipalities held in SDG&E PBOP plan trusts. |
| (3) | Bonds of U.S. issuers from diverse industries, primarily investment-grade. |
| (4) | Investment in common/collective trusts held in PBOP plan VEBA trusts. |
| (5) | Investments in venture capital and real estate funds, stated at net asset value, and derivative financial instruments. |
| (6) | Excludes cash and cash equivalents of $1 million held in SDG&E PBOP plan trusts and transfers payable to other plans of $6 million. |
| (7) | Excludes cash and cash equivalents of $3 million held in SoCalGas PBOP plan trusts and transfers receivable from other plans of $6 million. |
| (8) | Excludes cash and cash equivalents of $1 million and $3 million held in SDG&E and SoCalGas PBOP plan trusts, respectively. |
The investments of the pension master trust allocated to the pension and other postretirement benefit plans classified as Level 3 are private equity funds and represent a percentage of each plan’s total allocated assets as follows at December 31:
| LEVEL 3 INVESTMENT ASSETS |
| (Dollars in millions) |
| | Pension plans | | Other postretirement benefit plans |
| | Level 3 investment assets | | % of total investment assets | | Level 3 investment assets | | % of total investment assets |
| | 2014 | 2013 | | 2014 | 2013 | | 2014 | 2013 | | 2014 | 2013 |
| SDG&E | $ | 4 | $ | 6 | | ― | % | 1 | % | | $ | ― | $ | 1 | | ― | % | 1 | % |
| SoCalGas | | 8 | | 13 | | ― | | 1 | | | | 2 | | 2 | | ― | | ― | |
| All other | | 1 | | 2 | | ― | | 1 | | | | ― | | ― | | ― | | ― | |
Sempra Energy Consolidated | $ | 13 | $ | 21 | | ― | | 1 | | | $ | 2 | $ | 3 | | ― | | ― | |
The following table provides a reconciliation of changes in the fair value of investments classified as Level 3:
| LEVEL 3 RECONCILIATIONS |
| (Dollars in millions) |
| | Private equity funds |
| | | SDG&E | | SoCalGas | | All other | | Sempra Energy Consolidated |
| PENSION PLANS | | | | | | | | |
| Balance at January 1, 2013 | $ | 6 | $ | 13 | $ | 2 | $ | 21 |
| Realized gains | | 1 | | 2 | | ― | | 3 |
| Unrealized losses | | (1) | | (1) | | ― | | (2) |
| Sales | | ― | | (1) | | ― | | (1) |
| Balance at December 31, 2013 | | 6 | | 13 | | 2 | | 21 |
| Realized gains | | 1 | | 2 | | ― | | 3 |
| Unrealized losses | | (1) | | (2) | | ― | | (3) |
| Sales | | (2) | | (5) | | (1) | | (8) |
| Balance at December 31, 2014 | $ | 4 | $ | 8 | $ | 1 | $ | 13 |
| OTHER POSTRETIREMENT BENEFIT PLANS | | | | | | | | |
| Balance at January 1 and December 31, 2013 | $ | 1 | $ | 2 | $ | ― | $ | 3 |
| Unrealized losses | | (1) | | ― | | ― | | (1) |
| Balance at December 31, 2014 | $ | ― | $ | 2 | $ | ― | $ | 2 |
We expect to contribute the following amounts to our pension and other postretirement benefit plans in 2015:
| EXPECTED CONTRIBUTIONS | | | | | | |
| (Dollars in millions) | | | | | | |
| | Sempra Energy | | |
| | Consolidated | SDG&E | SoCalGas |
| Pension plans | $ | 31 | $ | 3 | $ | 2 |
| Other postretirement benefit plans | | 11 | | 9 | | ― |
The following table shows the total benefits we expect to pay for the next 10 years to current employees and retirees from the plans or from company assets.
| EXPECTED BENEFIT PAYMENTS |
| (Dollars in millions) |
| | Sempra Energy Consolidated | | SDG&E | | SoCalGas |
| | | Other | | | Other | | | Other |
| | Pension | postretirement | | Pension | postretirement | | Pension | postretirement |
| | benefits | benefits | | benefits | benefits | | benefits | benefits |
| 2015 | $ | 349 | $ | 50 | | $ | 92 | $ | 9 | | $ | 215 | $ | 39 |
| 2016 | | 333 | | 55 | | | 86 | | 10 | | | 211 | | 42 |
| 2017 | | 321 | | 58 | | | 87 | | 11 | | | 205 | | 45 |
| 2018 | | 313 | | 63 | | | 83 | | 11 | | | 200 | | 48 |
| 2019 | | 301 | | 66 | | | 80 | | 12 | | | 190 | | 50 |
| 2020-2024 | | 1,311 | | 346 | | | 360 | | 64 | | | 813 | | 264 |
Under Chilean law, Chilquinta Energía is required to pay all employees either (1) 30 percent of Chilquinta Energía’s taxable income after deducting a 10 percent return on equity, allocated in proportion to the annual salary of each employee or (2) 25 percent of each employee’s annual salary, with a maximum mandatory profit sharing of 4.75 months of Chile’s legal minimum salary. Chilquinta Energía has elected the second option but calculates the profit sharing amounts with actual employee salaries instead of the legal minimum salary, resulting in a higher cost. The amounts are paid out each pay period. Chilquinta Energía recorded annual profit sharing expense of $4 million for 2014, $4 million for 2013 and $6 million for 2012 related to this plan.
Under Peruvian law, Luz del Sur is required to pay their employees 5 percent of Luz del Sur’s taxable income, paid once a year and allocated as follows: 50 percent based on each employee’s annual hours worked and 50 percent based on each employee’s annual salary. Luz del Sur recorded annual profit sharing expense of $10 million for 2014, $9 million for 2013 and $10 million for 2012 related to this plan.
Sempra Energy offers trusteed savings plans to all domestic employees and to employees in Mexico. Participation in the plans is immediate for salary deferrals for all employees except for the represented employees at SoCalGas, who are eligible upon completion of one year of service. Subject to plan provisions, domestic employees may contribute from one percent to 50 percent of their regular earnings, subject to annual IRS limits. In Mexico, employees may contribute up to 2 percent of the portion of their base salary that is less than 25 times the minimum wage and may contribute up to 5 percent of any portion of their base salary that is greater than 25 times the minimum wage. Sempra Energy makes matching contributions for domestic employees after one year of the employee’s completed service and immediately for employees in Mexico. Employer contribution amounts and methodology vary by plan for domestic employees, but generally the contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments. Employer contributions for employees in Mexico equal the contributions made by the employee.
Beginning September 1, 2012 for the Sempra Energy, SDG&E and Mobile Gas savings plans and October 1, 2012 for the SoCalGas savings plan, employer contributions are invested based upon each employee’s investment elections in effect at the time of contribution. Prior to that, employer contributions were initially invested in Sempra Energy common stock, but the employee could transfer the contribution to other investments. Contributions are invested in Sempra Energy common stock, mutual funds and/or institutional trusts. Prior to the termination of the ESOP discussed below, employer contributions for substantially all plans were partially funded by the ESOP.
Contributions to the savings plans were as follows:
| CONTRIBUTIONS TO SAVINGS PLANS |
| (Dollars in millions) |
| | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 38 | $ | 35 | $ | 34 |
| SDG&E | | 15 | | 14 | | 16 |
| SoCalGas | | 18 | | 17 | | 15 |
The market value of Sempra Energy common stock held by the savings plans was $1.4 billion and $1.3 billion at December 31, 2014 and 2013, respectively.
EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)
Sempra Energy terminated the ESOP effective June 30, 2012, as all ESOP debt was paid and all shares were released from the ESOP Trust as of that date. Prior to the plan’s termination, all contributions to the ESOP Trust (Trust) were made by Sempra Energy; there were no contributions made by the participants. The Trust was used to fund part of the retirement savings plan described above. As Sempra Energy made contributions, the ESOP debt service was paid and shares were released in proportion to the total expected debt service. We charged compensation expense and credited equity for the market value of the released shares. Dividends on unallocated shares were used to pay debt service and were applied against the liability.
ESOP debt was paid down by a total of $10 million in 2012 when 153,625 shares of Sempra Energy common stock were released from the Trust in order to fund employer contributions to the Sempra Energy savings plan trust. Interest on the ESOP debt and dividends used for debt service were negligible in 2012.
NOTE 8. SHARE-BASED COMPENSATION
SEMPRA ENERGY EQUITY COMPENSATION PLANS
Sempra Energy has share-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of Sempra Energy. The plans permit a wide variety of share-based awards, including:
| § | non-qualified stock options |
| § | incentive stock options |
| § | stock appreciation rights |
Eligible California Utilities employees participate in Sempra Energy’s share-based compensation plans as a component of their compensation package.
In May 2013, shareholders approved the Sempra Energy 2013 Long-Term Incentive Plan. Upon approval, the remaining authorized shares from the Sempra Energy 2008 Long Term Incentive Plan and the 2008 Long Term Incentive Plan for EnergySouth, Inc. Employees and Other Eligible Individuals were applied to the number of shares authorized in the 2013 Plan.
At December 31, 2014, Sempra Energy had the following types of equity awards outstanding:
| § | Non-Qualified Stock Options: Options have an exercise price equal to the market price of the common stock at the date of grant, are service-based, become exercisable over a four-year period, and expire 10 years from the date of grant. Vesting and/or the ability to exercise may be accelerated upon a change in control, in accordance with severance pay agreements, in accordance with the terms of the grant, or upon eligibility for retirement. Options are subject to forfeiture or earlier expiration when an employee terminates employment. |
| § | Performance-Based Restricted Stock Units: These restricted stock unit awards generally vest in Sempra Energy common stock at the end of four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of market indices or based on earnings per common share (EPS) growth. For awards granted in 2013 or earlier, if Sempra Energy’s total return to shareholders exceeds target levels, up to an additional 50 percent of the number of granted restricted stock units may be issued. For awards granted in 2014, up to an additional 100 percent of the granted restricted stock units may be issued if total return to shareholders or EPS growth exceeds target levels. If Sempra Energy’s total return to shareholders or EPS growth is below the target levels, shares are subject to partial vesting on a pro rata basis. Vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, or in accordance with severance pay agreements. Dividend equivalents on shares subject to restricted stock units are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock units to which the dividends relate. |
| § | Service-Based Restricted Stock Units: Restricted stock units may also be service-based; these generally vest at the end of four years of service. Vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, in accordance with severance pay agreements, or at the discretion of the Compensation Committee of Sempra Energy’s Board of Directors. Dividend equivalents on shares subject to restricted stock units are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock units to which the dividends relate. |
| § | Other Restricted Stock Units: Restricted stock units were granted in 2014 in connection with the creation of the Cameron LNG Holdings joint venture. These awards vest to the extent that the Compensation Committee of Sempra Energy’s Board of Directors determines that the objectives of the joint venture are continuing to be achieved. These awards vest on the anniversary of the grant date over a period of either two or three years. Vesting may be subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, or in accordance with severance pay agreements. Dividend equivalents on shares subject to restricted stock units are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock units to which the dividends relate. |
| § | Restricted Stock: Restricted stock awards are solely service-based and are generally exercisable at the end of four years of service. Vesting is subject to earlier forfeiture upon termination of employment and accelerated vesting upon a change in control under the applicable long-term incentive plan, in accordance with severance pay agreements or upon eligibility for retirement. Holders of restricted stock have full voting rights. They also have full dividend rights; however, dividends paid on restricted stock held by officers are reinvested to purchase additional shares that become subject to the same vesting conditions as the restricted stock to which the dividends relate. |
In April 2013, the IEnova board of directors approved the IEnova 2013 Long-Term Incentive Plan. The purpose of this plan is to align the interests of employees and directors of IEnova with its shareholders. All awards issued from this plan and any related dividend equivalents will settle in cash based on the fair market value of the awards, based on IEnova’s common stock value, upon vesting. In 2014 and 2013, IEnova issued 468,339 and 1,014,899 restricted stock units from this plan, respectively, 962,122 of which remain outstanding at December 31, 2014.
SHARE-BASED AWARDS AND COMPENSATION EXPENSE
We measure and recognize compensation expense for all share-based payment awards made to our employees and directors based on estimated fair values on the date of grant. We recognize compensation costs net of an estimated forfeiture rate (based on historical experience) and recognize the compensation costs for non-qualified stock options and restricted stock and stock units on a straight-line basis over the requisite service period of the award, which is generally four years. However, in the year that an employee becomes eligible for retirement, the remaining expense related to the employee’s awards is recognized immediately. Substantially all awards outstanding are classified as equity instruments; therefore, we recognize additional paid in capital as we recognize the compensation expense associated with the awards.
At December 31, 2014, 6,562,347 shares were authorized and available for future grants of share-based awards. Our practice is to satisfy share-based awards by issuing new shares rather than by open-market purchases.
Total share-based compensation expense for all of Sempra Energy’s share-based awards was comprised as follows:
| SHARE-BASED COMPENSATION EXPENSE ― SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions, except per share amounts) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Share-based compensation expense, before income taxes | $ | 46 | $ | 38 | $ | 40 |
| Income tax benefit | | (18) | | (15) | | (16) |
| Share-based compensation expense, net of income taxes | $ | 28 | $ | 23 | $ | 24 |
| | | | | | | |
| Net share-based compensation expense, per common share | | | | | | |
| Basic | $ | 0.11 | $ | 0.09 | $ | 0.10 |
| Diluted | $ | 0.11 | $ | 0.09 | $ | 0.10 |
Sempra Energy Consolidated’s capitalized compensation cost was $5 million in 2014 and $4 million in each of 2013 and 2012.
We classify the tax benefits resulting from tax deductions in excess of the tax benefit related to compensation cost recognized for stock option exercises as financing cash flows.
Sempra Energy subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans and/or the subsidiaries are allocated a portion of the Sempra Energy plans’ corporate staff costs. Expenses and capitalized compensation costs recorded by SDG&E and SoCalGas were as follows:
SHARE-BASED COMPENSATION EXPENSE ― SDG&E AND SOCALGAS |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| SDG&E: | | | | | | |
| Compensation expense | $ | 8 | $ | 8 | $ | 8 |
| Capitalized compensation cost | | 3 | | 3 | | 3 |
| SoCalGas: | | | | | | |
| Compensation expense | $ | 8 | $ | 8 | $ | 7 |
| Capitalized compensation cost | | 2 | | 1 | | 1 |
SEMPRA ENERGY NON-QUALIFIED STOCK OPTIONS
We use a Black-Scholes option-pricing model (Black-Scholes model) to estimate the fair value of each non-qualified stock option grant. The use of a valuation model requires us to make certain assumptions about selected model inputs. Expected volatility is calculated based on the historical volatility of Sempra Energy’s stock price. We base the average expected life for options on the contractual term of the option and expected employee exercise and post-termination behavior.
The risk-free interest rate is based on U.S. Treasury zero-coupon issues with a remaining term equal to the expected life assumed at the date of the grant. No new options were granted in 2014, 2013 or 2012.
The following table shows a summary of non-qualified stock options at December 31, 2014 and activity for the year then ended:
| NON-QUALIFIED STOCK OPTIONS |
| |
| | | | Weighted- | |
| | | Weighted- | average | |
| | Shares | average | remaining | Aggregate |
| | under | exercise | contractual term | intrinsic value |
| | option | price | (in years) | (in millions) |
| Outstanding at December 31, 2013 | | 1,459,145 | $ | 53.18 | | | | |
| Exercised | | (699,783) | $ | 52.48 | | | | |
| Forfeited/canceled | | (1,950) | $ | 45.36 | | | | |
| Outstanding at December 31, 2014 | | 757,412 | $ | 53.84 | | 3.2 | $ | 44 |
| | | | | | | | | |
| Vested or expected to vest, at December 31, 2014 | | 757,412 | $ | 53.84 | | 3.2 | $ | 44 |
| Exercisable at December 31, 2014 | | 757,412 | $ | 53.84 | | 3.2 | $ | 44 |
The aggregate intrinsic value at December 31, 2014 is the total of the difference between Sempra Energy’s closing stock price and the exercise price for all in-the-money options. The aggregate intrinsic value for non-qualified stock options exercised in the last three years was
The total fair value of shares vested in the last three years was
We received cash from option exercises during 2014 totaling $37 million. There were no realized tax benefits for the share-based payment award deductions in 2014 over and above the $18 million income tax benefit shown above.
SEMPRA ENERGY RESTRICTED STOCK AWARDS AND UNITS
We use a Monte-Carlo simulation model to estimate the fair value of the restricted stock awards and units. Our determination of fair value is affected by the volatility of the stock price and the dividend yields for Sempra Energy and its peer group companies. The valuation also is affected by the risk-free rates of return, and a number of other variables. Below are key assumptions for 2014, 2013 and 2012 for Sempra Energy:
| | | 2014 | 2013 | 2012 |
| Risk-free rate of return | 1.2 | % | 0.6 | % | 0.6 | % |
| Annual dividend yield(1) | N/A | | 3.3 | | 3.4 | |
| Stock price volatility | 16 | | 19 | | 27 | |
| (1) | Annual dividend yield was not used in valuations performed in 2014. |
We provide below a summary of Sempra Energy’s restricted stock awards at December 31, 2014 and the activity during the year.
| RESTRICTED STOCK AWARDS |
| |
| | | Weighted- |
| | | average |
| | | grant-date |
| | Shares | fair value |
| Nonvested at December 31, 2013 | | 17,469 | $ | 62.43 |
| Vested | | (8,231) | $ | 60.87 |
| Nonvested at December 31, 2014 | | 9,238 | $ | 63.81 |
| Vested or expected to vest, at December 31, 2014 | | 9,238 | $ | 63.81 |
Total compensation cost related to nonvested restricted stock awards not yet recognized as of December 31, 2014 is negligible. The weighted-average per-share fair value for restricted stock awards granted was $75.82 in 2013 and $57.81 in 2012.
The total fair value of shares vested in the last three years was $1 million in each of 2014, 2013 and 2012.
We provide below a summary of Sempra Energy’s restricted stock units as of December 31, 2014 and the activity during the year.
| RESTRICTED STOCK UNITS | | | | |
| | | | | |
| | | Performance-based | | Service-based |
| | | restricted stock units | | restricted stock units(2) |
| | | | Weighted- | | | Weighted- |
| | | | average | | | average |
| | | | grant-date | | | grant-date |
| | | Units | fair value | | Units | fair value |
| Nonvested at December 31, 2013 | 3,164,561 | $ | 47.55 | | 215,598 | $ | 63.30 |
| Granted | 444,241 | $ | 88.01 | | 111,653 | $ | 91.54 |
| Vested | (720,600) | $ | 44.38 | | (21,268) | $ | 66.84 |
| Forfeited | (13,260) | $ | 57.83 | | (2,746) | $ | 67.79 |
| Nonvested at December 31, 2014(1) | 2,874,942 | $ | 54.55 | | 303,237 | $ | 73.41 |
| Vested or expected to vest, at December 31, 2014 | 2,816,676 | $ | 54.22 | | 290,822 | $ | 73.31 |
| (1) | Each unit represents the right to receive one share of our common stock if applicable performance conditions are satisfied. For all performance-based restricted stock units, up to an additional 50 percent (100 percent for awards granted in 2014) of the shares represented by the units may be issued if Sempra Energy exceeds target performance conditions. |
| (2) | Includes restricted stock units issued in 2014 in connection with the creation of the Cameron LNG Holdings joint venture. |
The total fair value of shares vested in 2014 was $33 million.
The $35 million of total compensation cost related to nonvested restricted stock units not yet recognized as of December 31, 2014 is expected to be recognized over a weighted-average period of 2.4 years. The weighted-average per-share fair values for performance-based restricted stock units granted were $57.55 in 2013 and $49.23 in 2012. The weighted-average per-share fair values for service-based restricted stock units granted were $72.71 in 2013 and $55.54 in 2012.
NOTE 9. DERIVATIVE FINANCIAL INSTRUMENTS
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 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 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, for the benefit of customers, 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 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 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: 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 Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. 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 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 December 31, 2014 and 2013 as follows:
| NET ENERGY DERIVATIVE VOLUMES |
| |
| | | | December 31, |
| Segment and Commodity | 2014 | 2013 |
| California Utilities: | | | |
| SDG&E: | | | |
| | Natural gas | 55 million MMBtu | 43 million MMBtu | (1) |
| | Congestion revenue rights | 27 million MWh | 33 million MWh | (2) |
| SoCalGas - natural gas | 1 million MMBtu | 2 million MMBtu | |
| | | | | | |
| Energy-Related Businesses: | | | |
| Sempra Natural Gas: | | | |
| Electric power | ― | 1 million MWh | |
| Natural gas | 29 million MMBtu | 15 million MMBtu | |
| (1) | Million British thermal units | |
| (2) | Megawatt hours | |
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.
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. 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 December 31, 2014 and 2013, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below, were:
| INTEREST RATE DERIVATIVES |
| (Dollars in millions) |
| | | December 31, 2014 | December 31, 2013 |
| | Notional debt | Maturities | Notional debt | Maturities |
| Sempra Energy Consolidated | | | | | | |
| | Cash flow hedges(1) | $ | 399 | 2015-2028 | $ | 413 | 2014-2028 |
| | Fair value hedges | | 300 | 2016 | | 300 | 2016 |
| SDG&E | | | | | | |
| | Cash flow hedge(1) | | 325 | 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 and joint ventures. On February 14, 2013, Sempra Mexico entered into cross-currency swap agreements, which were designated as cash flow hedges.
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.
FINANCIAL STATEMENT PRESENTATION
Each 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 Consolidated Balance Sheets at December 31, 2014 and 2013, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.
| DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS |
| (Dollars in millions) |
| | | December 31, 2014 |
| | | | | | | | | | Deferred |
| | | | | | | | | | credits |
| | | | Current | | | | Current | | and other |
| | | | assets: | | | | liabilities: | | liabilities: |
| | | | Fixed-price | | Investments | | Fixed-price | | Fixed-price |
| | | | contracts | | and other | | contracts | | contracts |
| | | | and other | | assets: | | and other | | and other |
| | | derivatives(1) | | Sundry | | derivatives(2) | | derivatives |
| Sempra Energy Consolidated: | | | | | | | | |
| Derivatives designated as hedging instruments: | | | | | | | | |
| Interest rate and foreign exchange instruments(3) | $ | 10 | $ | 3 | $ | (17) | $ | (109) |
| Commodity contracts not subject to rate recovery | | 25 | | ― | | ― | | ― |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Interest rate instruments | | 8 | | 27 | | (7) | | (22) |
| Commodity contracts not subject to rate recovery | | 143 | | 32 | | (135) | | (29) |
| Associated offsetting commodity contracts | | (129) | | (27) | | 129 | | 27 |
| Associated offsetting cash collateral | | (11) | | ― | | ― | | ― |
| Commodity contracts subject to rate recovery | | 36 | | 76 | | (36) | | (20) |
| Associated offsetting commodity contracts | | (3) | | (1) | | 3 | | 1 |
| Associated offsetting cash collateral | | ― | | ― | | 23 | | 13 |
| Net amounts presented on the balance sheet | | 79 | | 110 | | (40) | | (139) |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 14 | | ― | | ― | | ― |
| Total(4) | $ | 93 | $ | 110 | $ | (40) | $ | (139) |
| SDG&E: | | | | | | | | |
| Derivatives designated as hedging instruments: | | | | | | | | |
| Interest rate instruments(3) | $ | ― | $ | ― | $ | (16) | $ | (31) |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Commodity contracts subject to rate recovery | | 32 | | 76 | | (32) | | (20) |
| Associated offsetting commodity contracts | | ― | | (1) | | ― | | 1 |
| Associated offsetting cash collateral | | ― | | ― | | 23 | | 13 |
| Net amounts presented on the balance sheet | | 32 | | 75 | | (25) | | (37) |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 12 | | ― | | ― | | ― |
| Total(4) | $ | 44 | $ | 75 | $ | (25) | $ | (37) |
| SoCalGas: | | | | | | | | |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Commodity contracts subject to rate recovery | $ | 4 | $ | ― | $ | (4) | $ | ― |
| Associated offsetting commodity contracts | | (3) | | ― | | 3 | | ― |
| Net amounts presented on the balance sheet | | 1 | | ― | | (1) | | ― |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 2 | | ― | | ― | | ― |
| Total | $ | 3 | $ | ― | $ | (1) | $ | ― |
| (1) | Included in Current Assets: Other for SoCalGas. | | | | | | | | |
| (2) | Included in Current Liabilities: Other for SoCalGas. | | | | | | | | |
| (3) | Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. |
| (4) | Normal purchase contracts previously measured at fair value are excluded. |
| DERIVATIVE INSTRUMENTS ON THE CONSOLIDATED BALANCE SHEETS |
| (Dollars in millions) |
| | | December 31, 2013 |
| | | | | | | | | | Deferred |
| | | | | | | | | | credits |
| | | | Current | | | | Current | | and other |
| | | | assets: | | | | liabilities: | | liabilities: |
| | | | Fixed-price | | Investments | | Fixed-price | | Fixed-price |
| | | | contracts | | and other | | contracts | | contracts |
| | | | and other | | assets: | | and other | | and other |
| | | derivatives(1) | | Sundry | | derivatives(2) | | derivatives |
| Sempra Energy Consolidated: | | | | | | | | |
| Derivatives designated as hedging instruments: | | | | | | | | |
| Interest rate and foreign exchange instruments(3) | $ | 14 | $ | 12 | $ | (18) | $ | (75) |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Interest rate instruments | | 8 | | 22 | | (7) | | (17) |
| Commodity contracts not subject to rate recovery | | 47 | | 7 | | (51) | | (5) |
| Associated offsetting commodity contracts | | (43) | | (5) | | 43 | | 5 |
| Associated offsetting cash collateral | | ― | | ― | | 1 | | ― |
| Commodity contracts subject to rate recovery | | 35 | | 72 | | (10) | | (8) |
| Associated offsetting commodity contracts | | (3) | | (2) | | 3 | | 2 |
| Net amounts presented on the balance sheet | | 58 | | 106 | | (39) | | (98) |
| Additional cash collateral for commodity contracts | | | | | | | | |
| not subject to rate recovery | | 17 | | ― | | ― | | ― |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 31 | | ― | | ― | | ― |
| Total(4) | $ | 106 | $ | 106 | $ | (39) | $ | (98) |
| SDG&E: | | | | | | | | |
| Derivatives designated as hedging instruments: | | | | | | | | |
| Interest rate instruments(3) | $ | ― | $ | ― | $ | (16) | $ | (39) |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Commodity contracts subject to rate recovery | | 34 | | 72 | | (9) | | (8) |
| Associated offsetting commodity contracts | | (3) | | (2) | | 3 | | 2 |
| Net amounts presented on the balance sheet | | 31 | | 70 | | (22) | | (45) |
| Additional cash collateral for commodity contracts | | | | | | | | |
| not subject to rate recovery | | 1 | | ― | | ― | | ― |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 29 | | ― | | ― | | ― |
| Total(4) | $ | 61 | $ | 70 | $ | (22) | $ | (45) |
| SoCalGas: | | | | | | | | |
| Derivatives not designated as hedging instruments: | | | | | | | | |
| Commodity contracts subject to rate recovery | $ | 1 | $ | ― | $ | (1) | $ | ― |
| Net amounts presented on the balance sheet | | 1 | | ― | | (1) | | ― |
| Additional cash collateral for commodity contracts | | | | | | | | |
| not subject to rate recovery | | 2 | | ― | | ― | | ― |
| Additional cash collateral for commodity contracts | | | | | | | | |
| subject to rate recovery | | 2 | | ― | | ― | | ― |
| Total | $ | 5 | $ | ― | $ | (1) | $ | ― |
| (1) | Included in Current Assets: Other for SoCalGas. | | | | | | | | |
| (2) | Included in Current Liabilities: Other for SoCalGas. | | | | | | | | |
| (3) | Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE. |
| (4) | Normal purchase contracts previously measured at fair value are excluded. |
The effects of derivative instruments designated as hedges on the Consolidated Statements of Operations and on Other Comprehensive Income (Loss) (OCI) and Accumulated Other Comprehensive Income (AOCI) for the years ended December 31 were:
| FAIR VALUE HEDGE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions) |
| | | | Gain (loss) on derivatives recognized in earnings |
| | | | Years ended December 31, |
| | Location | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | | |
| | Interest rate instruments | Interest Expense | $ | 8 | $ | 8 | $ | 6 |
| | Interest rate instruments | Other Income, Net | | (3) | | (7) | | 3 |
| | Total(1) | | $ | 5 | $ | 1 | $ | 9 |
| (1) | There were gains of $9 million from hedge ineffectiveness in 2014. All other changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net. There was no hedge ineffectiveness in 2013 and 2012. |
| CASH FLOW HEDGE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions) |
| | | Pretax gain (loss) | | | Gain (loss) reclassified |
| | | recognized in OCI | | | from AOCI into earnings |
| | | (effective portion) | | | (effective portion) |
| | | Years ended December 31, | | | Years ended December 31, |
| | | 2014 | | 2013 | | 2012 | | Location | | 2014 | | 2013 | | 2012 |
| Sempra Energy Consolidated: | | | | | | | | | | | | | | |
| | Interest rate and foreign | | | | | | | | | | | | | | |
| | exchange instruments(1) | $ | (24) | $ | 1 | $ | (22) | | Interest Expense | $ | (21) | $ | (11) | $ | (9) |
| | | | | | | | | | Gain on Sale of Equity | | | | | | |
| | Interest rate instruments | | 3 | | ― | | ― | | Interests and Assets | | 3 | | ― | | ― |
| | | | | | | | | | Equity Earnings (Losses), | | | | | | |
| | Interest rate instruments | | (127) | | 15 | | (10) | | Before Income Tax | | (10) | | (10) | | (6) |
| | Commodity contracts not | | | | | | | | Revenues: Energy-Related | | | | | | |
| | subject to rate recovery | | 19 | | (4) | | (1) | | Businesses | | 8 | | 1 | | ― |
| | Total(2) | $ | (129) | $ | 12 | $ | (33) | | | $ | (20) | $ | (20) | $ | (15) |
| SDG&E: | | | | | | | | | | | | | | |
| | Interest rate instruments(1)(3) | $ | (9) | $ | 8 | $ | (16) | | Interest Expense | $ | (11) | $ | (9) | $ | (5) |
| SoCalGas: | | | | | | | | | | | | | | |
| | Interest rate instrument(3) | $ | ― | $ | ― | $ | ― | | Interest Expense | $ | (1) | $ | (1) | $ | (2) |
| (1) | Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. |
| (2) | There was $1 million, $1 million and $2 million of hedge ineffectiveness related to these cash flow hedges in 2014, 2013 and 2012, respectively. |
| (3) | There was negligible hedge ineffectiveness related to these cash flow hedges at SDG&E and SoCalGas in 2014, 2013 and 2012. |
For Sempra Energy Consolidated we expect that losses of $19 million, which are net of income tax benefit, that are currently recorded in AOCI (including $13 million in noncontrolling interests, of which $12 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 that 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 December 31, 2014 is approximately 14 years and 4 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at equity method investees is 21 years.
The effects of derivative instruments not designated as hedging instruments on the Consolidated Statements of Operations for the years ended December 31 were:
| UNDESIGNATED DERIVATIVE IMPACT ON THE CONSOLIDATED STATEMENTS OF OPERATIONS |
| (Dollars in millions) |
| | | | Gain (loss) on derivatives recognized in earnings |
| | | | Years ended December 31, |
| | | Location | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated: | | | | | | | |
| | Interest rate and foreign | | | | | | | |
| | exchange instruments | Other Income, Net | $ | (24) | $ | 17 | $ | 10 |
| | Foreign exchange instruments | Equity Earnings, Net of Income Tax | | (5) | | (4) | | ― |
| | Commodity contracts not subject | Revenues: Energy-Related | | | | | | |
| | to rate recovery | Businesses | | 17 | | (1) | | 7 |
| | Commodity contracts not subject | Cost of Natural Gas, Electric | | | | | | |
| | to rate recovery | Fuel and Purchased Power | | 3 | | ― | | ― |
| | Commodity contracts not subject | | | | | | | |
| | to rate recovery | Operation and Maintenance | | (4) | | 1 | | 1 |
| | Commodity contracts subject | Cost of Electric Fuel | | | | | | |
| | to rate recovery | and Purchased Power | | (10) | | 53 | | 69 |
| | Commodity contracts subject | | | | | | | |
| | to rate recovery | Cost of Natural Gas | | ― | | ― | | (2) |
| | Total | | $ | (23) | $ | 66 | $ | 85 |
| SDG&E: | | | | | | | |
| | Commodity contracts not subject | | | | | | | |
| | to rate recovery | Operation and Maintenance | $ | (1) | $ | ― | $ | ― |
| | Commodity contracts subject | Cost of Electric Fuel | | | | | | |
| | to rate recovery | and Purchased Power | | (10) | | 53 | | 69 |
| | Total | | $ | (11) | $ | 53 | $ | 69 |
| SoCalGas: | | | | | | | |
| | Commodity contracts not subject | | | | | | | |
| | to rate recovery | Operation and Maintenance | $ | (2) | $ | 1 | $ | 1 |
| | Commodity contracts subject | | | | | | | |
| | to rate recovery | Cost of Natural Gas | | ― | | ― | | (2) |
| | Total | | $ | (2) | $ | 1 | $ | (1) |
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 December 31, 2014 and 2013 is $9 million and $3 million, respectively. At December 31, 2014, if the credit ratings of Sempra Energy were reduced below investment grade, $9 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 at December 31, 2014 and 2013 is $2 million and $3 million, respectively. At December 31, 2014, if the credit ratings of SDG&E were reduced below investment grade, $2 million of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra Energy, 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.
NOTE 10. FAIR VALUE MEASUREMENTS
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 as of December 31, 2014 and 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 9 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 December 31, 2014 and 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.
| RECURRING FAIR VALUE MEASURES ― SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | Fair value at December 31, 2014 |
| | | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | | | | |
| Equity securities | $ | 655 | $ | ― | $ | ― | $ | ― | $ | 655 |
| Debt securities: | | | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | | | |
| U.S. government corporations and agencies | | 62 | | 47 | | ― | | ― | | 109 |
| Municipal bonds | | ― | | 129 | | ― | | ― | | 129 |
| Other securities | | ― | | 207 | | ― | | ― | | 207 |
| Total debt securities | | 62 | | 383 | | ― | | ― | | 445 |
| Total nuclear decommissioning trusts(2) | | 717 | | 383 | | ― | | ― | | 1,100 |
| Interest rate and foreign exchange instruments | | ― | | 48 | | ― | | ― | | 48 |
| Commodity contracts not subject to rate recovery | | 28 | | 16 | | ― | | (11) | | 33 |
| Commodity contracts subject to rate recovery | | ― | | 1 | | 107 | | 14 | | 122 |
| Total | $ | 745 | $ | 448 | $ | 107 | $ | 3 | $ | 1,303 |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Interest rate and foreign exchange instruments | $ | ― | $ | 155 | $ | ― | $ | ― | $ | 155 |
| Commodity contracts not subject to rate recovery | | 3 | | 9 | | ― | | (4) | | 8 |
| Commodity contracts subject to rate recovery | | ― | | 52 | | ― | | (36) | | 16 |
| Total | $ | 3 | $ | 216 | $ | ― | $ | (40) | $ | 179 |
| | | | | | | | | | | | |
| | Fair value at December 31, 2013 |
| | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | | | | |
| Equity securities | $ | 614 | $ | ― | $ | ― | $ | ― | $ | 614 |
| Debt securities: | | | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | | | |
| U.S. government corporations and agencies | | 59 | | 58 | | ― | | ― | | 117 |
| Municipal bonds | | ― | | 111 | | ― | | ― | | 111 |
| Other securities | | ― | | 153 | | ― | | ― | | 153 |
| Total debt securities | | 59 | | 322 | | ― | | ― | | 381 |
| Total nuclear decommissioning trusts(2) | | 673 | | 322 | | ― | | ― | | 995 |
| Interest rate and foreign exchange instruments | | ― | | 56 | | ― | | ― | | 56 |
| Commodity contracts not subject to rate recovery | | 1 | | 5 | | ― | | 17 | | 23 |
| Commodity contracts subject to rate recovery | | 2 | | 1 | | 99 | | 31 | | 133 |
| Total | $ | 676 | $ | 384 | $ | 99 | $ | 48 | $ | 1,207 |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Interest rate and foreign exchange instruments | $ | ― | $ | 117 | $ | ― | $ | ― | $ | 117 |
| Commodity contracts not subject to rate recovery | | 4 | | 8 | | ― | | (5) | | 7 |
| Commodity contracts subject to rate recovery | | ― | | 13 | | ― | | ― | | 13 |
| Total | $ | 4 | $ | 138 | $ | ― | $ | (5) | $ | 137 |
| (1) | Includes the effect of the contractual ability to settle contracts under master netting agreements with cash collateral, as well as cash collateral not offset. |
| (2) | Excludes cash balances and cash equivalents. | | | | | | | | | | |
| RECURRING FAIR VALUE MEASURES ― SDG&E |
| (Dollars in millions) |
| | Fair value at December 31, 2014 |
| | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | | | | |
| Equity securities | $ | 655 | $ | ― | $ | ― | $ | ― | $ | 655 |
| Debt securities: | | | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | | | |
| U.S. government corporations and agencies | | 62 | | 47 | | ― | | ― | | 109 |
| Municipal bonds | | ― | | 129 | | ― | | ― | | 129 |
| Other securities | | ― | | 207 | | ― | | ― | | 207 |
| Total debt securities | | 62 | | 383 | | ― | | ― | | 445 |
| Total nuclear decommissioning trusts(2) | | 717 | | 383 | | ― | | ― | | 1,100 |
| Commodity contracts subject to rate recovery | | ― | | ― | | 107 | | 12 | | 119 |
| Total | $ | 717 | $ | 383 | $ | 107 | $ | 12 | $ | 1,219 |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Interest rate instruments | $ | ― | $ | 47 | $ | ― | $ | ― | $ | 47 |
| Commodity contracts not subject to rate recovery | | 1 | | ― | | ― | | (1) | | ― |
| Commodity contracts subject to rate recovery | | ― | | 51 | | ― | | (36) | | 15 |
| Total | $ | 1 | $ | 98 | $ | ― | $ | (37) | $ | 62 |
| | | | | | | | | | | |
| | Fair value at December 31, 2013 |
| | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Nuclear decommissioning trusts | | | | | | | | | | |
| Equity securities | $ | 614 | $ | ― | $ | ― | $ | ― | $ | 614 |
| Debt securities: | | | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | | | |
| U.S. government corporations and agencies | | 59 | | 58 | | ― | | ― | | 117 |
| Municipal bonds | | ― | | 111 | | ― | | ― | | 111 |
| Other securities | | ― | | 153 | | ― | | ― | | 153 |
| Total debt securities | | 59 | | 322 | | ― | | ― | | 381 |
| Total nuclear decommissioning trusts(2) | | 673 | | 322 | | ― | | ― | | 995 |
| Commodity contracts not subject to rate recovery | | ― | | ― | | ― | | 1 | | 1 |
| Commodity contracts subject to rate recovery | | 1 | | 1 | | 99 | | 29 | | 130 |
| Total | $ | 674 | $ | 323 | $ | 99 | $ | 30 | $ | 1,126 |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Interest rate instruments | $ | ― | $ | 55 | $ | ― | $ | ― | $ | 55 |
| Commodity contracts subject to rate recovery | | ― | | 12 | | ― | | ― | | 12 |
| Total | $ | ― | $ | 67 | $ | ― | $ | ― | $ | 67 |
| (1) | Includes the effect of the contractual ability to settle contracts under master netting agreements with cash collateral, as well as cash collateral not offset. |
| (2) | Excludes cash balances and cash equivalents. | | | | | | | | | | |
| RECURRING FAIR VALUE MEASURES ― SOCALGAS |
| (Dollars in millions) |
| | | Fair value at December 31, 2014 |
| | | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Commodity contracts subject to rate recovery | $ | ― | $ | 1 | $ | ― | $ | 2 | $ | 3 |
| Total | $ | ― | $ | 1 | $ | ― | $ | 2 | $ | 3 |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Commodity contracts not subject to rate recovery | $ | 2 | $ | ― | $ | ― | $ | (2) | $ | ― |
| Commodity contracts subject to rate recovery | | ― | | 1 | | ― | | ― | | 1 |
| Total | $ | 2 | $ | 1 | $ | ― | $ | (2) | $ | 1 |
| | | | | | | | | | | | |
| | | Fair value at December 31, 2013 |
| | | | Level 1 | | Level 2 | | Level 3 | | Netting(1) | | Total |
| Assets: | | | | | | | | | | |
| Commodity contracts not subject to rate recovery | $ | ― | $ | ― | $ | ― | $ | 2 | $ | 2 |
| Commodity contracts subject to rate recovery | | 1 | | ― | | ― | | 2 | | 3 |
| Total | $ | 1 | $ | ― | $ | ― | $ | 4 | $ | 5 |
| | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Commodity contracts subject to rate recovery | $ | ― | $ | 1 | $ | ― | $ | ― | $ | 1 |
| Total | $ | ― | $ | 1 | $ | ― | $ | ― | $ | 1 |
| (1) | Includes the effect of the contractual ability to settle contracts under master netting agreements with cash collateral, as well as cash collateral not offset. |
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) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Balance at January 1 | $ | 99 | $ | 61 | $ | 23 |
| Realized and unrealized gains | | 15 | | 11 | | 31 |
| Allocated transmission instruments | | 19 | | 51 | | 58 |
| Settlements | | (26) | | (24) | | (51) |
| Balance at December 31 | $ | 107 | $ | 99 | $ | 61 |
| Change in unrealized gains or losses relating to | | | | | | |
| instruments still held at December 31 | $ | 8 | $ | 11 | $ | 17 |
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 ISO, 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 December 31, 2014, the auction prices ranged from $(16) per MWh to $8 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. At December 31, 2013, the auction prices ranged from $(6) 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 9. Realized gains and losses associated with CRRs are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.
Derivative Positions Net of Cash Collateral
Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.
The following table provides the amount of fair value of cash collateral receivables that were not offset in the Consolidated Balance Sheets at December 31, 2014 and 2013:
| | December 31, |
| (Dollars in millions) | 2014 | 2013 |
| Sempra Energy Consolidated | $ | 14 | $ | 48 |
| SDG&E | | 12 | | 30 |
| SoCalGas | | 2 | | 4 |
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 December 31:
| FAIR VALUE OF FINANCIAL INSTRUMENTS |
| (Dollars in millions) |
| | | December 31, 2014 |
| | | Carrying | | Fair Value |
| | | amount | | Level 1 | Level 2 | Level 3 | Total |
| Sempra Energy Consolidated: | | | | | | | | | | | |
Total long-term debt(1)(2) | $ | 12,347 | | $ | ― | $ | 12,782 | $ | 917 | $ | 13,699 |
| Preferred stock of subsidiary | | 20 | | | ― | | 23 | | ― | | 23 |
| SDG&E: | | | | | | | | | | | |
Total long-term debt(2)(3) | $ | 4,461 | | $ | ― | $ | 4,563 | $ | 425 | $ | 4,988 |
| SoCalGas: | | | | | | | | | | | |
Total long-term debt(4) | $ | 1,913 | | $ | ― | $ | 2,124 | $ | ― | $ | 2,124 |
| Preferred stock | | 22 | | | ― | | 25 | | ― | | 25 |
| | | | | | | | | | | | | |
| | | December 31, 2013 |
| | | Carrying | | Fair Value |
| | | amount | | Level 1 | Level 2 | Level 3 | Total |
| Sempra Energy Consolidated: | | | | | | | | | | | |
Total long-term debt(1)(2) | $ | 12,022 | | $ | ― | $ | 11,925 | $ | 751 | $ | 12,676 |
| Preferred stock of subsidiary | | 20 | | | ― | | 20 | | ― | | 20 |
| SDG&E: | | | | | | | | | | | |
Total long-term debt(2)(3) | $ | 4,386 | | $ | ― | $ | 4,226 | $ | 335 | $ | 4,561 |
| SoCalGas: | | | | | | | | | | | |
Total long-term debt(4) | $ | 1,413 | | $ | ― | $ | 1,469 | $ | ― | $ | 1,469 |
| Preferred stock | | 22 | | | ― | | 22 | | ― | | 22 |
| (1) | Before reductions for unamortized discount (net of premium) of $21 million and $17 million at December 31, 2014 and 2013, respectively, and excluding build-to-suit and capital leases of $310 million and $195 million at December 31, 2014 and 2013, respectively, and commercial paper classified as long-term debt of $200 million at December 31, 2013. We discuss our long-term debt in Note 5. |
| (2) | Level 3 instruments include $325 million and $335 million at December 31, 2014 and 2013, respectively, related to Otay Mesa VIE. |
| (3) | Before reductions for unamortized discount of $11 million at December 31, 2014 and 2013, and excluding capital leases of $234 million and $179 million at December 31, 2014 and 2013, respectively. |
| (4) | Before reductions for unamortized discount of $8 million and $4 million at December 31, 2014 and 2013, respectively, and excluding capital leases of $1 million and $2 million at December 31, 2014 and 2013, respectively. |
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 13 below.
Non-Recurring Fair Value Measures – Sempra Energy Consolidated
Energía Sierra Juárez
In July 2014, Sempra Mexico completed the sale of a 50-percent interest in the 155-MW first phase of its Energía Sierra Juárez wind project to a wholly owned subsidiary of InterGen N.V. for cash proceeds of $24 million, net of $2 million cash sold, as discussed in Note 3. Sempra Mexico recognized a pretax gain on the sale of $19 million ($14 million after-tax). Upon deconsolidation, our equity method investment in Energía Sierra Juárez was measured at fair value, which resulted in a $7 million after-tax gain attributable to a remeasurement of the retained investment to fair value. The fair value measurement was based on the cash sales price of $26 million paid by InterGen N.V., a nonrelated party and market participant. Use of this market participant input as the indicator of fair value is a Level 2 measurement in the fair value hierarchy.
Rockies Express
We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 4.
In 2012, we recorded a $400 million pretax impairment of our investment in Rockies Express. In the second quarter of 2012, the noncash impairment charge of $300 million ($179 million after-tax) primarily resulted from the continuing decline in basis differential associated with shale gas production zones coming on line, assumptions related to the re-contracting of the long-term transportation agreements, and the refinancing of the existing project level debt, discussed further below. The fair value measurement was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measurements, which we discuss in Note 1 under “Fair Value Measurements.” We considered a market participant’s view of the total value for Rockies Express, based on an estimation of the future cash distributions it would be able to generate, adjusted for our 25-percent ownership interest. To estimate future cash distributions, we considered factors impacting Rockies Express’ ability to pay future distributions including:
| § | the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties; |
| § | Rockies Express’ future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal; |
| § | prospects for generating attractive revenues and cash flows beyond 2019, including natural gas’ future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and |
| § | discount rates commensurate with the risks inherent in the cash flows. |
In the third quarter of 2012, KMI reached an agreement with Tallgrass, which closed in the fourth quarter of 2012, to sell its asset group as mandated by the FTC, which group included its interest in Rockies Express. Events in the third quarter of 2012 related to this agreement also provided us with additional market participant data. We therefore updated our analysis of the fair value of our investment in Rockies Express as of September 30, 2012 to reflect these additional inputs and recorded an additional impairment charge of $100 million ($60 million after-tax). This fair value measurement in the third quarter was based primarily on the Level 2 input. We believe this is useful and reliable information, but we considered that it may be impacted by the FTC’s requirement for KMI to sell its interest in Rockies Express. To reflect this uncertainty, our updated analysis included the less subjective Level 2 market participant input as the primary indicator of fair value, with less weight ascribed to value based on estimated discounted cash flows as discussed above and in the table below. The updates to the cash flow analysis used in determining fair value in the second quarter reflected discussions with Tallgrass as to the strategic direction they are planning to take with their equity partners for Rockies Express, as well as additional discussions with other market participants. Tallgrass became the operator of Rockies Express in November 2012.
We believe our analysis formed a reasonable estimate of the fair value of Rockies Express at the measurement date of September 30, 2012. This estimate included the material input described above, which was generally observable during the period most relevant to our analysis. Regarding the unobservable inputs, significant uncertainties exist with regard to REX’s ability to secure attractive revenues beyond 2019. Accordingly, our analysis suggested that the fair value of our investment in Rockies Express could be materially different from the value we estimated at that time. For example, if REX is able to sustain the level of revenues currently generated beyond 2019, the value of our investment in Rockies Express would be materially enhanced and the indicated value of our investment in Rockies Express could be significantly higher. Conversely, if REX is unable to sell its transport capacity at sufficient rates or in sufficient volumes beyond 2019, the fair value of our investment in Rockies Express could be materially lower than our carrying amount. Separately, future events involving Rockies Express equity could occur and may also provide additional information regarding the fair value of our investment in Rockies Express.
Sempra Natural Gas developed the models and scenarios used to measure the fair value of our investment in Rockies Express. This modeling used inputs from external sources as described above and in the table below, as well as internally available data, such as operating and maintenance budgets used for financial planning purposes. External experts that forecast the future price of natural gas at various physical locations were also engaged to help validate certain scenarios and modeling assumptions. The fair value measurements were reviewed in detail by Sempra Natural Gas’ financial management, as well as Sempra Energy’s financial management team.
The following table summarizes significant inputs impacting non-recurring fair value measures related to our investments in Energía Sierra Juárez and Rockies Express:
| NON-RECURRING FAIR VALUE MEASURES ― SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) |
| | | | | | | % of | | |
| | Estimated | | Fair | Fair value | | |
| | fair | | value | measure- | | Range of |
| | value | Valuation technique | hierarchy | ment | Inputs used to develop measurement | inputs |
| Investment in | | | | | | | | |
| Energía Sierra | | | | | | | | |
| Juárez | $ | 26 | (1) | Market approach | Level 2 | 100% | Equity sale offer price | 100% |
| Investment in | | | | | | | | |
| Rockies Express | $ | 369 | (2) | Market approach | Level 2 | 67% | Equity sale offer price | 100% |
| | | | | | | | | |
| | | | | | | | | |
| | | | | Probability weighted | Level 3 | 33% | Combined transportation rate assumption(3) | 6% - 78% |
| | | | | discounted cash flow | | | Counterparty credit risk on existing contracts | Low |
| | | | | | | | Operation and maintenance escalation rate | 0% - 1% |
| | | | | | | | Forecasted interest rate on debt to be refinanced | 5% - 10% |
| | | | | | | | Discount rate | 8% - 10% |
| (1) | At measurement date of July 16, 2014. At December 31, 2014, our investment in Energía Sierra Juárez had a carrying value of $25 million, reflecting subsequent equity method activity to record distributions and earnings. |
| (2) | At measurement date of September 30, 2012. At December 31, 2014, our investment in Rockies Express had a carrying value of $340 million, reflecting subsequent equity method activity to record distributions and earnings. |
| (3) | Transportation rate beyond existing contract terms as a percentage of current mean REX rates. |
The table below shows the details of preferred stock for SoCalGas. All series of SDG&E preferred stock were redeemed during 2013 as we discuss below.
| PREFERRED STOCK OUTSTANDING |
| (Dollars in millions, except per share amounts) | | | | | | |
| | | | | December 31, |
| | | | | 2014 | 2013 |
| $25 par value, authorized 1,000,000 shares: | | | | | | |
| 6% Series, 79,011 shares outstanding | | | $ | 3 | $ | 3 |
| 6% Series A, 783,032 shares outstanding | | | | 19 | | 19 |
| SoCalGas - Total preferred stock | | | | 22 | | 22 |
| Less: 50,970 shares of the 6% Series outstanding owned by Pacific Enterprises | | (2) | | (2) |
| Sempra Energy - Total preferred stock of subsidiary | | | $ | 20 | $ | 20 |
| | |
Following are the attributes of each company’s preferred stock. No amounts currently outstanding are subject to mandatory redemption.
SDG&E
On October 15, 2013, SDG&E redeemed all six series of its outstanding shares of contingently redeemable preferred stock for $82 million, including a $3 million early call premium. Each series was redeemed for cash at redemption prices ranging from $20.25 to $26 per share plus accrued dividends up to the redemption date of $1 million. The early call premium is presented as Call Premium on Preferred Stock of Subsidiary on Sempra Energy’s and Call Premium on Preferred Stock on SDG&E’s Consolidated Statements of Operations. The shares are no longer outstanding.
SDG&E is currently authorized to issue up to 45 million shares of preferred stock. The stock’s rights, preferences, privileges and restrictions would be established by the board of directors at the time of issuance.
SOCALGAS
| § | None of SoCalGas’ outstanding preferred stock is callable. |
| § | All outstanding series have one vote per share, cumulative preferences as to dividends and liquidation preferences of $25 per share plus any unpaid dividends. |
SoCalGas currently is also authorized to issue 5 million shares of series preferred stock and 5 million shares of preference stock, both without par value and with cumulative preferences as to dividends and liquidation value. The preference stock would rank junior to all series of preferred stock. Other rights and privileges of the stock would be established by the board of directors at the time of issuance.
NOTE 12. SEMPRA ENERGY – SHAREHOLDERS’ EQUITY AND EARNINGS PER SHARE
The following table provides the per share computations for our earnings for years ended December 31. Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the year. 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 AND DIVIDENDS DECLARED |
| (Dollars in millions, except per share amounts; shares in thousands) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| Numerator: | | | | | | |
| Earnings/Income attributable to common shareholders | $ | 1,161 | $ | 1,001 | $ | 859 |
| | | | | | | |
| Denominator: | | | | | | |
| Weighted-average common shares outstanding for basic EPS | | 245,891 | | 243,863 | | 241,347 |
| Dilutive effect of stock options, restricted stock awards and | | | | | | |
| restricted stock units | | 4,764 | | 5,469 | | 5,346 |
| Weighted-average common shares outstanding for diluted EPS | | 250,655 | | 249,332 | | 246,693 |
| | | | | | | |
| Earnings per share: | | | | | | |
| Basic | $ | 4.72 | $ | 4.10 | $ | 3.56 |
| Diluted | $ | 4.63 | $ | 4.01 | $ | 3.48 |
| | | | | | | |
| Dividends declared per share of common stock | $ | 2.64 | $ | 2.52 | $ | 2.40 |
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 of dilutive common stock equivalents 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 2014 or 2013, and 40,000 such options outstanding during 2012.
During 2014, 2013 and 2012, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits recognized 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 recognized 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 RSAs and 4,087 antidilutive RSUs from the application of unearned compensation in the treasury stock method in 2014. There were no such antidilutive RSAs or RSUs in 2013. There were 1,934 such antidilutive RSAs and 7,673 such antidilutive RSUs in 2012.
Each performance-based RSU represents the right to receive up to 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:
| Four-year cumulative total shareholder return ranking versus S&P 500 Utilities Index(1) | Number of Sempra Energy common shares received for each performance-based restricted stock unit(2)(3) |
| 90th percentile or above (2014 awards only) | 2.0 |
| 75th percentile (maximum for awards prior to 2014) | 1.5 |
| 50th percentile | 1.0 |
| 35th percentile or below | ― |
| (1) | If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each RSU. |
| (2) | Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate. |
| (3) | If performance falls between the tiers shown above, we calculate the payout using linear interpolation. |
Beginning in January 2014, we issued performance-based RSUs representing the right to receive up to 2.0 shares of Sempra Energy common stock based on Sempra Energy’s four-year EPS compound annual growth rate beginning January 1, 2014 and ending on December 31, 2017. These RSU awards vest as follows:
| Four-year earnings per share compound annual growth rate | Number of Sempra Energy common shares received for each performance-based restricted stock unit(1)(2) |
| 8.0% or above | 2.0 |
| 6.7% | 1.5 |
| 4.4% | 1.0 |
| 3.3% or below | ― |
| (1) | Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate. |
| (2) | If performance falls between the tiers shown above, we calculate the payout using linear interpolation. |
Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with the creation of the Cameron LNG Holdings joint venture represent the right to receive up to 1.0 share over the course or at the end of the service period and have the same dividend equivalent rights as performance-based RSUs. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. 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. Due to market fluctuations of both Sempra Energy stock and the comparative indices, dilutive performance-based RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 949,351; 641,751 and 1,134,456 for the years ended December 31, 2014, 2013 and 2012, respectively.
We are authorized to issue 750,000,000 shares of no-par-value common stock. In addition, we are authorized to issue 50,000,000 shares of preferred stock having rights, preferences and privileges that would be established by the Sempra Energy board of directors at the time of issuance.
Common stock activity consisted of the following:
| COMMON STOCK ACTIVITY |
| | | |
| | | Years ended December 31, |
| | | | 2014 | | 2013 | | 2012 |
| Common shares outstanding, January 1 | | 244,461,327 | | 242,368,836 | | 239,934,681 |
| Restricted stock units vesting(1) | | 989,027 | | 1,491,170 | | 683,416 |
| Stock options exercised | | 699,783 | | 1,237,348 | | 1,876,303 |
| Savings plan issuance | | 398,042 | | ― | | ― |
| Common stock investment plan(2) | | 205,203 | | ― | | ― |
| Restricted stock issuances | | ― | | 21,121 | | 2,580 |
| Shares released from ESOP(3) | | ― | | ― | | 153,625 |
| Shares repurchased(4) | | (422,498) | | (657,148) | | (281,769) |
| Common shares outstanding, December 31 | | 246,330,884 | | 244,461,327 | | 242,368,836 |
| (1) | Includes dividend equivalents. |
| (2) | Participants in the Direct Stock Purchase Plan may reinvest dividends to purchase newly issued shares. |
| (3) | We released the last shares from the ESOP in April 2012. These shares were unallocated and therefore excluded from the computation of EPS. |
| (4) | From time to time, we purchase shares of our common stock from restricted stock plan participants who elect to sell a sufficient number of vesting restricted shares or units to meet minimum statutory tax withholding requirements. |
Our board of directors has the discretion to determine the payment and amount of future dividends.
NOTE 13. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)
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 Consolidated Statements of Operations.
SONGS Outage and Retirement
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 generator. 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 replacement 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 15.
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 was 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).
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) held a settlement conference in March 2014 to discuss the terms to resolve the SONGS OII, and in April 2014, SDG&E, along with Edison, TURN, ORA and two other intervenors who joined the Settlement Agreement to the SONGS OII proceeding (collectively, the Settling Parties), filed a Settlement Agreement with the CPUC. On September 5, 2014, the CPUC issued a ruling proposing specific changes that included, as they relate to SDG&E, greater ratepayer benefit from third party cost recoveries and funding of a research program to reduce greenhouse gas emissions at a shareholder cost of $1 million per year for 5 years.
On September 23, 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which amended the Settlement Agreement to adopt all of the modifications and clarifications requested in the CPUC ruling. On October 9, 2014, the CPUC issued a proposed decision approving the Amended Settlement Agreement, which was adopted by the CPUC as a final decision on November 20, 2014.
As approved by the CPUC, the Amended Settlement Agreement constitutes 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 Amended 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 (except for the allocation to ratepayers of any recoveries as described below) or proceedings addressing decommissioning activities and costs.
In November 2014, in accordance with the Amended Settlement Agreement, SDG&E filed an advice letter seeking authority from the CPUC, among other things, to implement the terms and establish the revenue requirement established by the Amended Settlement Agreement in rates starting January 1, 2015. In December 2014, the CPUC approved the advice letter and authorized SDG&E to update rates accordingly, subject to revision pending the results of a CPUC review of the changes to the revenue requirement proposed by SDG&E for consistency with the terms of the approved settlement decision. Upon conclusion of the CPUC’s review, SDG&E expects to receive a final disposition letter from the CPUC either confirming that SDG&E’s proposed rate changes were in compliance with the approved settlement decision or identifying changes that need to be made to the proposed rates and the resultant annual SONGS revenue requirement. Upon receipt of the final disposition letter, SDG&E will determine if final adjustment is necessary to increase or decrease the amount of the SONGS regulatory asset. SDG&E currently expects the CPUC to issue this final disposition letter in the first half of 2015.
The following is a summary of the Amended Settlement Agreement as it relates to SDG&E.
Disallowances, Refunds and Rate Recoveries
Based on the final decision, 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 rate of return or SONGS ROR). |
This results in a SONGS ROR of 2.75 percent for the period from February 1, 2012 through December 31, 2012 and 2.35 percent for the period from 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 2012 and 2013 operations and maintenance expenses; in addition, SDG&E will be authorized to recover in rates the recorded costs for the 2012 refueling outage of Unit 2, subject to customary prudency review; |
| § | be required to file an application in 2015 to recover in rates its 2014 recorded operation and maintenance expenses and non-operating operations and maintenance expenses; |
| § | 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; |
| § | be authorized to recover in rates through its fuel and purchased power balancing account (ERRA), subject to the normal CPUC compliance reviews, 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 replacement power purchase costs through June 6, 2013 (the date of SONGS’ retirement) were approximately $165 million, using the methodology followed in the SONGS OII; and |
| § | have a five-year funding commitment of $1 million per year to the University of California (UC) Energy Institute (or other existing UC entity engaged in energy technology development) to create a Research Development and Demonstration program, whose goal would be to deploy new technologies, methodologies, and /or design modifications to reduce greenhouse gas (GHG) emissions, particularly at current and future generating plants in California. This term was a modification requested by the CPUC. |
Potential Third Party Recoveries
The Amended Settlement Agreement also addresses how potential recoveries from third parties will be allocated between ratepayers and SDG&E, as we describe below.
As we discuss in more detail in Note 15, 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 Amended 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 attributable to the NEIL accidental outage policy exceeds such costs, recoveries will be allocated 95 percent to ratepayers and 5 percent to SDG&E. To the extent SDG&E’s share of recoveries from other NEIL policies (such as the accidental property damage policy) exceeds such costs, recoveries will be allocated 82.5 percent to ratepayers and 17.5 percent to SDG&E.
As we discuss in more detail in Note 15, 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 Amended Settlement Agreement, recoveries from MHI, 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 MHI exceeds such costs, they will be allocated 50 percent to SDG&E and 50 percent to ratepayers.
The Amended Settlement Agreement provides that the resolution of the claims with NEIL and the dispute with MHI do not require CPUC 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, and |
| § | allow the CPUC to review documentation of final resolution of third-party litigation and litigation costs to ensure that the ratepayer refund calculations are accurately calculated and that the litigation costs are not exorbitant in relation to the recovery obtained. |
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 regarding the accidental outage policy by the end of 2015.
The Amended 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 would be credited to ratepayers.
Accounting and Financial Impacts
In the second quarter of 2013, SDG&E reported a pretax loss from plant closure of $200 million ($119 million after-tax) as a result of its initial assessment of the financial impact of the outcome of the SONGS OII proceeding. In the first quarter of 2014, as a result of entering into the Settlement Agreement, 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 included a $17 million charge to reduce certain tax regulatory assets that may no longer be recoverable in rates pursuant to the Settlement Agreement. In the third quarter of 2014, SDG&E recorded a charge for the impact of the modifications and clarifications in the Amended Settlement Agreement on the regulatory asset, which charge was not material. In the fourth quarter of 2014, in conjunction with filing the advice letter regarding revenue requirement and determining the timing of refunds to ratepayers, SDG&E recorded a charge to Plant Closure Loss of $19 million pretax ($12 million after-tax). The total Plant Closure Loss in 2014 was $6 million pretax ($21 million after-tax). A regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is recorded on the Consolidated Balance Sheets of Sempra Energy and SDG&E in Other Regulatory Assets (long-term). The amount of this regulatory asset is $308 million at December 31, 2014.
SDG&E does not expect that implementation of the Amended Settlement Agreement will have a material adverse impact on its future results of operations or financial condition.
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 generator. 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 (PSDAR), an irradiated fuel management plan (IFMP) and a site-specific decommissioning cost estimate (DCE). Edison submitted each of the PSDAR, the IFMP and the DCE to the NRC in September 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. Decommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work will be done when Units 2 and 3 are decommissioned. At December 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 or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. 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 Units 2 and 3 decommissioning costs incurred, and such expenditures will be reimbursed from the NDT upon that approval.
SDG&E currently anticipates a decision regarding its ability to use the monies in the NDT by the end of 2015.
In December 2012, SDG&E and Edison filed a joint application 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 of decommissioning SONGS. SDG&E is currently authorized to recover $8 million annually to fund additional investments in the NDT. In December 2014, the CPUC issued a decision authorizing SDG&E to continue to collect and contribute to the NDT $8 million annually.
In December 2014, SDG&E and Edison filed a joint application with the CPUC submitting a detailed study of the costs to decommission SONGS Units 2 and 3. The cost study estimates the total decommissioning costs for Units 2 and 3 at $4.411 billion, of which SDG&E’s share is $899 million. The joint application requests that the CPUC determine the cost study to be reasonable and asks that SDG&E’s contributions to the NDT be set at zero ($0.00) beginning January 1, 2016, given the current expectation that the NDT will be sufficiently funded over time. The application also requests that the CPUC approve a standardized process for regularly reviewing the reasonableness of decommissioning activities and costs and authorizing disbursements from the NDT.
On September 5, 2014, the NRC approved Edison’s February 2014 request (made on behalf of SONGS co-owners) for exemptions from various federal decommissioning requirements. These exemptions provide NRC approval for SONGS co-owners to use NDT funds for all types of decommissioning activity costs, including fuel management and site restoration costs. As noted above, however, CPUC approval to access the NDT to pay for such costs is still required for SDG&E and Edison to use NDT funds.
Edison’s submission of the PSDAR and the DCE in September 2014 allows the SONGS co-owners to commence major decommissioning activities, and submission of the DCE provides the NRC authorization for the SONGS co-owners to access the majority of their decommissioning trust funds, both starting 90 days after the NRC receives the documents, unless the NRC staff raises objections. No objections were received during the 90-day period.
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 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. We provide additional fair value disclosures for the trusts in Note 10.
| NUCLEAR DECOMMISSIONING TRUSTS |
| (Dollars in millions) |
| | | | Gross | Gross | Estimated |
| | | | unrealized | unrealized | fair |
| | | Cost | gains | losses | value |
| At December 31, 2014: | | | | | | | | |
| Debt securities: | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | |
U.S. government corporations and agencies(1) | $ | 103 | $ | 6 | $ | ― | $ | 109 |
Municipal bonds(2) | | 121 | | 8 | | ― | | 129 |
Other securities(3) | | 206 | | 7 | | (6) | | 207 |
| Total debt securities | | 430 | | 21 | | (6) | | 445 |
| Equity securities | | 215 | | 444 | | (4) | | 655 |
| Cash and cash equivalents | | 30 | | 1 | | ― | | 31 |
| Total | $ | 675 | $ | 466 | $ | (10) | $ | 1,131 |
| At December 31, 2013: | | | | | | | | |
| Debt securities: | | | | | | | | |
| Debt securities issued by the U.S. Treasury and other | | | | | | | | |
| U.S. government corporations and agencies | $ | 116 | $ | 3 | $ | (2) | $ | 117 |
| Municipal bonds | | 110 | | 2 | | (1) | | 111 |
| Other securities | | 155 | | 3 | | (5) | | 153 |
| Total debt securities | | 381 | | 8 | | (8) | | 381 |
| Equity securities | | 207 | | 409 | | (2) | | 614 |
| Cash and cash equivalents | | 39 | | ― | | ― | | 39 |
| Total | $ | 627 | $ | 417 | $ | (10) | $ | 1,034 |
| (1) | Maturity dates are 2016-2060. | | | | | | | | |
| (2) | Maturity dates are 2015-2047. | | | | | | | | |
| (3) | Maturity dates are 2015-2111. | | | | | | | | |
The following table shows the proceeds from sales of securities in the trusts and gross realized gains and losses on those sales.
| SALES OF SECURITIES |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Proceeds from sales(1) | $ | 601 | $ | 685 | $ | 723 |
| Gross realized gains | | 11 | | 26 | | 21 |
| Gross realized losses | | (11) | | (18) | | (13) |
| (1) | Excludes securities that are held to maturity. |
Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.
Customer contribution amounts are determined by the CPUC using estimates of after-tax investment returns, decommissioning costs, and decommissioning cost escalation rates. Changes in investment returns and decommissioning costs may result in a change in future customer contributions.
Asset Retirement Obligation and Spent Nuclear Fuel
SDG&E’s asset retirement obligation related to decommissioning costs for the SONGS units was $713 million at December 31, 2014. That amount includes the cost to decommission Units 2 and 3, and the remaining cost to complete the decommissioning of Unit 1, which is substantially complete. The asset retirement obligation at December 31, 2014 is based on an updated cost study prepared in 2014 that reflects the acceleration of the start of decommissioning Units 2 and 3 as a result of the early closure of the plant. SDG&E’s share of decommissioning costs in 2014 dollars is approximately $937 million.
Unit 1 was permanently shut down in 1992, and physical decommissioning began in January 2000. Most structures, foundations and large components have been dismantled, removed and disposed of. Spent nuclear fuel has been removed from the Unit 1 Spent Fuel Pool and stored on-site in an independent spent fuel storage installation (ISFSI) licensed by the NRC. The decommissioning of Unit 1 remaining structures (subsurface and intake/discharge) will take place as Units 2 and 3 are decommissioned. The ISFSI will be decommissioned after a permanent storage facility becomes available and the DOE removes the spent fuel from the site. The Unit 1 reactor vessel is expected to remain on site until Units 2 and 3 are fully decommissioned. Until then, SONGS owners are responsible for interim storage of spent nuclear fuel at SONGS until the DOE accepts it for final disposal. Spent nuclear fuel for Units 2 and 3 has been stored in the SONGS spent fuel pools for each reactor and in the ISFSI.
We provide additional information about SONGS in Note 15.
NOTE 14. CALIFORNIA UTILITIES’ REGULATORY 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.
The California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements. In February 2015, the CPUC issued a scoping memo setting the schedule for the proceeding, including the issuance of a proposed decision by the end of 2015.
In May 2013, the CPUC approved a final decision in the California Utilities’ 2012 GRC (Final 2012 GRC Decision). The Final 2012 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 2012 GRC Decision of $69 million and $37 million, respectively, in the second quarter of 2013. For SDG&E and SoCalGas, respectively, these amounts included 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 being 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 December 31, 2014, SDG&E reported on its Consolidated Balance Sheet $162 million as a regulatory asset, all classified as current, representing the retroactive revenue from the Final 2012 GRC Decision to be recovered by SDG&E in rates through December 2015. At December 31, 2014, SoCalGas reported on its Consolidated Balance Sheet a regulatory asset of $52 million, all classified as current, representing the retroactive revenue from the Final GRC Decision to be recovered in rates through December 2015.
A CPUC cost of capital proceeding determines a utility’s authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE), weighted on a basis consistent with the authorized capital structure. The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover the cost of debt and equity used to finance their investment in CPUC-regulated electric distribution and generation as well as natural gas distribution, transmission and storage assets.
In addition, a cost of capital proceeding also addresses the automatic cost of capital adjustment mechanism (CCM) which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings. The market-based benchmark for SDG&E’s and SoCalGas’ CCM is the 12-month average monthly A-rated utility bond index, as published by Moody’s for the 12-month period of October 1st through September 30th (CCM Period) of each calculation year. In the last cost of capital proceeding, SDG&E’s and SoCalGas’ CCM benchmark rate was set at 4.24 percent. If at the end of the CCM Period the monthly average benchmark rate falls outside of the established range of 3.24 percent to 5.24 percent, SDG&E’s and SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the benchmark rate. In addition, the authorized recovery rate for SDG&E’s and SoCalGas’ cost of debt and preferred stock would be adjusted to their respective actual weighted average costs, with no change to the authorized capital structure. All three adjustments with the new rate would become effective on January 1st of the following year in which the benchmark range was exceeded. For the twelve-month period ended September 30, 2014, the 12-month average of monthly Moody’s A-rated utility bond index was 4.46 percent.
The CCM only applies during the intervening years between scheduled cost of capital proceedings. In the year the cost of capital proceeding is scheduled, the cost of capital proceeding takes precedence over CCM and will set new rates for the following year.
In December 2014, the CPUC granted both SDG&E and SoCalGas an extension of their filing deadlines for their next cost of capital applications by one year, from April 2015 to April 2016. The CPUC also extended the current CCM until the April 2016 filing date. The one year extension was made in response to a joint request by SDG&E, SoCalGas, Pacific Gas and Electric Company (PG&E) and Edison with the CPUC in November 2014.
SDG&E’s current CPUC-authorized ROR is 7.79 percent and SoCalGas’ current CPUC-authorized ROR is 8.02 percent based on their authorized capital structures as follows:
| COST OF CAPITAL AND AUTHORIZED RATE STRUCTURE |
| | | |
| SDG&E | | | | SoCalGas |
| Authorized weighting | | Authorized rate of recovery | | Weighted authorized ROR | | | | Authorized weighting | | Authorized rate of recovery | | Weighted authorized ROR |
| 45.25% | | 5.00% | | 2.26% | | Long-Term Debt | | 45.60% | | 5.77% | | 2.63% |
| 2.75% | | 6.22% | | 0.17% | | Preferred Stock | | 2.40% | | 6.00% | | 0.14% |
| 52.00% | | 10.30% | | 5.36% | | Common Equity | | 52.00% | | 10.10% | | 5.25% |
| 100.00% | | | | 7.79% | | | | 100.00% | | | | 8.02% |
SDG&E files separately with the FERC for authorized ROE on FERC-regulated electric transmission operations and assets as described below in “Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters”.
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 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. As a result of on-going efforts since this original filing, the California Utilities have been able to eliminate over two hundred miles of pipeline from the testing scope and have revised their total estimated cost for Phase 1 to $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). 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.
In April 2012, the CPUC transferred the PSEP to the Triennial Cost Allocation Proceeding (TCAP) and authorized 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.
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.
In June 2014, the CPUC issued a final decision in the TCAP proceeding addressing SDG&E’s and SoCalGas’ PSEP. Specifically, the decision:
| § | approved the utilities’ model for implementing PSEP; |
| § | approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in the regulatory accounts authorized by the CPUC as noted above; |
| § | approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and |
| § | established the criteria to determine the amounts that would not be eligible for cost recovery, including: |
| ▢ | certain costs incurred or to be incurred searching for pipeline test records, |
| ▢ | the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and |
| ▢ | any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing. |
As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods for which SoCalGas was disallowed recovery. After taking the amounts disallowed for recovery into consideration, as of December 31, 2014, SDG&E and SoCalGas have recorded PSEP costs of $2 million and $85 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with the TCAP decision, SDG&E and SoCalGas are authorized to file an application with the CPUC for recovery of such costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ending December 31, 2015. SoCalGas and SDG&E currently expect to be able to file such applications by the third quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e. a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017). In response to this significant delay in receiving the authority to recover PSEP costs incurred from customers, in October 2014, SDG&E and SoCalGas filed a request with the CPUC for authority to recover PSEP costs from customers as incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in the subsequent year. In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. We requested a decision in 2015.
In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. The ORA and TURN alleged that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In November 2014, the CPUC denied the ORA and TURN request for rehearing of the decision adopting the PSEP. In December 2014, ORA and TURN sought rehearing of the CPUC’s decision on rehearing. In late December 2014, SoCalGas and SDG&E filed their opposition to this second application for rehearing, and are continuing to implement PSEP in accordance with the June 2014 CPUC decision.
Southern Gas System Reliability Project
In December 2013, SoCalGas and SDG&E filed a joint application with the CPUC seeking authority to recover the full cost of the Southern Gas System Reliability Project. Also known as the North-South Gas Project, the project will enhance reliability on the southern portions of the California Utilities’ integrated natural gas transmission system (Southern System). The estimated cost of the project, as originally filed, is between $800 million to $850 million. As proposed, the project consists of three components: 1) constructing an approximately 60-mile, 36-inch natural gas transmission pipeline between the SoCalGas Adelanto compressor station and the Moreno pressure limiting station; 2) upgrading the Adelanto compressor station; and 3) constructing an approximately 31-mile, 36-inch pipeline from the Moreno pressure limiting station to a pressure limiting station in Whitewater. In November 2014, the California Utilities revised the scope of the proposed project to only include connecting the Adelanto compressor station and Moreno pressure limiting station with approximately 65 miles of 36-inch pipeline and upgrading the Adelanto compressor station, and eliminating the Moreno-Whitewater pipeline. As a result of the revised scope of the project, the California Utilities assessed the estimated cost of the revised project and confirmed the original cost estimate of $800 million to $850 million, while still providing almost all of the benefits for customers. Given the revised project scope, an updated schedule in this proceeding is currently being developed. Depending upon this updated schedule and subject to environmental permitting and approval by the CPUC, we expect the project to be in service by the end of 2019.
Utility Incentive Mechanisms
The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals. Generally, for performance-based awards, if performance is above or below specific benchmarks, the utility is eligible for financial awards or subject to financial penalties. SDG&E has incentive mechanisms associated with:
SoCalGas has incentive mechanisms associated with:
| § | natural gas procurement |
| § | unbundled natural gas storage and system operator hub services |
Incentive awards are included in our earnings when we receive any required CPUC approval of the award. We would record penalties for results below the specified benchmarks in earnings when we believe it is more likely than not that the CPUC would assess a penalty.
The CPUC established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In December 2012, the CPUC issued a final decision adopting a mechanism for the 2010–2012 program cycle and approving shareholder awards of $3.3 million for SDG&E and $2.7 million for SoCalGas for their energy efficiency program performance in 2010 under the mechanism. The decision established an annual process for the utilities to obtain awards for their performance in 2011 and 2012.
In December 2013, the CPUC awarded $3.1 million to SoCalGas and $3.9 million to SDG&E for their 2011 program year results. In December 2014, the CPUC approved awards to SoCalGas and SDG&E of $5.9 million and $7.5 million, respectively, for program years 2012 and 2013. Of these amounts, SoCalGas and SDG&E will receive initial 2013 program awards of $1.5 million and $2.5 million, respectively, and the CPUC will address the remaining 2013 program awards in 2015.
Unbundled Natural Gas Storage and System Operator Hub Services
The CPUC has established a revenue sharing mechanism, effective through 2015, which provides for the sharing between ratepayers and SoCalGas (shareholders) of the net revenues generated by SoCalGas’ unbundled natural gas storage and system operator hub services. Annual net revenues (revenues less allocated service costs) under the mechanism are shared on a graduated basis, as follows:
| § | the first $15 million of net revenue to be shared 90 percent ratepayers/10 percent shareholders; |
| § | the next $15 million of net revenue to be shared 75 percent ratepayers/25 percent shareholders; |
| § | all additional net revenues to be shared evenly between ratepayers and shareholders; and |
| § | the maximum total annual shareholder-allocated portion of the net revenues cannot exceed $20 million. |
SoCalGas is seeking to extend the mechanism through at least 2019, but revise the sharing to 60 percent ratepayers/40 percent shareholders to reflect changes in the market for storage services. The current annual shareholder earnings cap of $20 million would remain in place.
The California Utilities procure natural gas on behalf of their core natural gas customers. The CPUC has established incentive mechanisms to allow the California Utilities the opportunity to share in the savings and/or costs from buying natural gas for their core customers at prices below or above monthly market-based benchmarks. SoCalGas procures natural gas for SDG&E’s core natural gas customers’ requirements. SoCalGas’ gas cost incentive mechanism (GCIM) is applied on the combined portfolio basis.
The CPUC issued final decisions in 2014, 2013 and 2012 approving GCIM awards for SoCalGas of $5.8 million, $5.4 million and $6.2 million, respectively, for the 12-month periods ending March 31, 2013, 2012 and 2011, respectively. SoCalGas filed an application with the CPUC for approval of a $13.7 million GCIM award for natural gas procured for its core customers during the 12-month period ending March 31, 2014. In February 2015, the CPUC issued a final decision approving the $13.7 million GCIM award as requested by SoCalGas. SoCalGas will recognize this award in its financial results for the first quarter of 2015.
The CPUC may establish operational incentives and associated performance benchmarks as part of a general rate case or cost of service proceeding. In the California Utilities’ Final 2012 GRC Decision described above, SDG&E was directed to establish a performance measure and incentive for electric reliability. In September 2014, the CPUC approved SDG&E’s proposed mechanism, which will apply to calendar year 2015 and be considered in the 2016 GRC. The CPUC did not establish any operational incentives for SoCalGas in the Final 2012 GRC Decision.
We discuss regulatory and other matters related to SONGS in Note 13.
Power Procurement and Resource Planning
Background—Electric Industry Regulation
California’s legislative response to the 2000 – 2001 energy crisis resulted in the California Department of Water Resources (DWR) purchasing a substantial portion of power for California’s electricity users. In 2001, the DWR entered into long-term contracts with suppliers, including Sempra Natural Gas, to provide power for the utility procurement customers of each of the California investor-owned utilities (IOUs), including SDG&E. The CPUC allocates the power and its administrative responsibility, including collection of power contract costs from utility customers, among the IOUs. The last of these power contracts expired in 2013, with one remaining transportation contract allocated to SDG&E that will expire in 2018.
Renewable Energy
SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission, which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking proceeding in May 2011 to address the implementation of the 33% RPS Program.
The 33% RPS Program contains flexible compliance mechanisms that can be used to comply with or meet the 33% RPS Program mandates in 2011 and beyond. The mechanisms provide for a CPUC waiver under certain conditions, including: 1) a finding of inadequate transmission; 2) delays in the start-up of commercial operations of renewable energy projects due to permitting or interconnection; or 3) unexpected curtailment by an electric system balancing authority, such as the California ISO.
SDG&E continues to procure renewable energy supplies to achieve the 33% RPS Program requirements. A substantial number of these supply contracts, however, are contingent upon many factors, including:
| § | access to electric transmission infrastructure; |
| § | timely regulatory approval of contracted renewable energy projects; |
| § | the renewable energy project developers’ ability to obtain project financing and permitting; and |
| § | successful development and implementation of the renewable energy technologies. |
In August 2014, SDG&E made a required filing with the CPUC indicating that its procurement of renewable energy during the period January 1, 2011 through December 31, 2013 exceeded the 20-percent minimum amount required by RPS. SDG&E believes it will be able to comply with the 33% RPS Program requirements based on its contracting activity and, if necessary, application of the flexible compliance mechanisms. SDG&E’s failure to comply with the RPS Program requirements could subject it to CPUC-imposed penalties, which could materially affect its business, cash flows, financial condition, results of operations and/or prospects. The limit on the total amount of penalties for failure to comply with the RPS requirements is $75 million for the first compliance period (2011-2013); $75 million for the second compliance period (2014-2016); $100 million for the third compliance period (2017-2020); and $25 million for each annual compliance period beginning in 2021.
Cleveland National Forest Transmission Projects
SDG&E filed an application with the CPUC in October 2012 for a permit to construct various transmission replacement projects in and around the Cleveland National Forest (CNF). The proposed projects will replace and fire-harden five existing transmission lines and six existing distribution lines at an estimated cost of between $400 million and $450 million. As directed by the CPUC, SDG&E filed an amended application in June 2013 to provide notice of certain alternatives proposed by the U.S. Forest Service (USFS) in connection with SDG&E’s request for a Master Special Use Permit (MSUP). USFS approval of the MSUP will establish land rights and conditions for SDG&E’s continued operation and maintenance of facilities located within the CNF. CPUC approval is not required for the MSUP, even though construction of the projects is subject to review by both the USFS and CPUC. A draft environmental impact report (EIR/EIS), developed jointly by the CPUC and USFS, was issued in September 2014 and a final EIR/EIS is expected in early 2015. SDG&E currently expects a CPUC decision approving the transmission projects in the second half of 2015 and then expects the various phases of this project to be placed in service starting in 2016 and continuing through the end of the project in 2019.
Sycamore-Peñasquitos Transmission Project
In March 2014, the CAISO selected SDG&E, as a result of a competitive bid process, to construct the Sycamore-Peñasquitos 230-kilovolt (kV) transmission project, which will provide a 16.7-mile transmission connection between SDG&E’s Sycamore Canyon and Peñasquitos substations. In July 2014, the CPUC notified SDG&E that the application requesting a Certificate of Public Convenience and Necessity (CPCN) to construct the line, which was filed with the CPUC in April 2014, is complete. The estimated $120 million to $150 million project was identified by the CAISO and 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. In October 2014, SDG&E filed a request with FERC seeking, among other things, a 100 basis point ROE adder for this project. We expect a FERC decision on this filing in 2015. 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 requesting a CPCN for 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 draft environmental report to be issued in early 2015 and a final CPUC decision approving the estimated $400 million to $500 million project in the first half of 2016. 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 2020.
South Bay Substation and Relocation Project
SDG&E filed an application in 2010 with the CPUC for a permit to construct a new substation, the Bay Boulevard substation, to replace the aging and obsolete South Bay substation to accommodate regional energy demands. The existing substation will be demolished when the Bay Boulevard 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 Bay Boulevard substation at SDG&E’s proposed site. The project is estimated at $145 million to $175 million. In March 2014, the California Coastal Commission approved the coastal development permit for the project, subject to certain additional environmental enhancements. In July 2014, SDG&E filed a petition with the CPUC to request modifications to the prior CPUC decision to authorize the additional construction activities required by the coastal development permit. In January 2015, the CPUC issued a decision approving the petition for modification. SDG&E is in the process of obtaining the remaining approvals and permits required to begin construction. SDG&E currently expects the project to be in service in 2017.
Federal Energy Regulatory Commission (FERC) Formulaic Rate Matters
In February 2013, SDG&E submitted its Electric Transmission Formula Rate (TO4) filing with the FERC to set the rate making methodology and rate of return for SDG&E’s FERC-regulated electric transmission operations and assets for a multi-year period beginning September 1, 2013. The TO4 filing proposed a FERC ROE of 11.3 percent and requested: 1) rates to be determined by a base period of historical costs and a forecast of capital investments and 2) a true-up period similar to balancing account treatment that is designed to provide SDG&E earnings of no more and no less than its actual cost of service including its authorized return on investment. In June and July 2013, the FERC issued orders accepting the filing, subject to refund, and established settlement and hearing procedures, with rates being effective September 1, 2013.
On January 31, 2014, SDG&E filed an uncontested multi-party settlement at the FERC regarding the TO4 filing. The settlement, approved by FERC in May 2014, will be in effect through December 31, 2018, is subject to a one-time right of termination by any party, and established a 10.05 percent ROE. The settlement also requires SDG&E to make annual information filings on December 1 of a given year to update rates for the following calendar year. SDG&E also has the right to file for any ROE incentives that might apply under FERC rules. SDG&E’s debt to equity ratio will be set annually based on the actual ratio at the end of each year.
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 overcollected 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 May 2014, the CPUC issued a final decision approving SDG&E’s proposed 2014 ERRA revenue requirement of $1.23 billion, an increase of $242 million compared to the 2013 ERRA revenue requirement of $988 million. SDG&E implemented the increased revenue requirement on August 1, 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 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 for the 12-month period ended March 31, 2012, resulting from settlement activities for 2007 wildfire claims. 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 on the merits.
SDG&E intends to pursue recovery of the costs it has incurred for settlement activities associated with the 2007 wildfire claims allocated to SDG&E’s CPUC-regulated operations by filing an application with the CPUC in 2015. SDG&E will continue to assess the potential for recovery of these costs in rates. We discuss the impact should SDG&E conclude that recovery in rates is no longer probable in “Legal Proceedings — SDG&E — 2007 Wildfire Litigation” in Note 15. We discuss how we assess the probability of recovery of our regulatory assets in Note 1.
Advanced Metering Infrastructure
In November 2011, the ORA and TURN filed a joint petition requesting that the CPUC reconsider its prior approval of SoCalGas’ advanced metering infrastructure (AMI) project and stay AMI deployment while the CPUC considered the request. In June 2014, the CPUC denied the ORA/TURN petition, and SoCalGas is continuing its deployment of AMI pursuant to the April 2010 CPUC decision approving the project.
NOTE 15. COMMITMENTS AND CONTINGENCIES
We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount 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 December 31, 2014, Sempra Energy’s accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $68 million. At December 31, 2014, accrued liabilities for legal proceedings for SDG&E and SoCalGas were $49 million and $12 million, respectively.
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.”
A September 2008 staff report issued by the CPUC’s Consumer Protection and Safety Division, now known as the Safety and Enforcement Division (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 all but five of these lawsuits. Four of these remaining cases have been scheduled for damages-only trials in 2015, where the value of any compensatory damages resulting from the fires will be determined.
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 party contractors and Cox. 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 agreed to 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. Through December 31, 2014, SDG&E has expended $483 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.
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 these claims of the approximately 6,500 plaintiffs for a total of approximately $1.3 billion. Substantially all of the remaining plaintiffs have submitted settlement demands and damage estimates, which total approximately $60 million. SDG&E does not expect 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 until those cases are resolved. SDG&E has established reserves for the wildfire litigation as we discuss below.
SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve 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 December 31, 2014, Sempra Energy and SDG&E have recorded assets of $373 million in Other Regulatory Assets (long-term) on their Consolidated Balance Sheets, including $366 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 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. 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 December 31, 2014, the resulting after-tax charge against earnings would have been up to approximately $217 million. Recovery of these costs 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.
We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 14 and discuss how we assess the probability of recovery of our regulatory assets in Note 1.
Sunrise Powerlink Electric Transmission Line
In February 2011, opponents of the Sunrise Powerlink, a 500-kV electric transmission line between the Imperial Valley and the San Diego region that was energized and placed in service in June 2012, 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 was submitted in 2013 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 asserted that it was owed additional compensation above the fixed-fee portion of the contract. In May 2013, the contractor filed claims totaling $180 million, including one in San Diego County for the sum of $99 million and the other in Imperial County for the sum of $81 million, seeking foreclosure of previously filed mechanics liens. In October 2013, the contractor served a Demand for Arbitration pursuant to contractual provisions and SDG&E counterclaimed against the contractor. In December 2014, SDG&E and the contractor settled their claims with SDG&E agreeing to pay the contractor $65 million as compensation for additional costs incurred by the contractor for the work performed.
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 sought 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. In January 2015, SDG&E settled this claim for an insignificant amount and the appeal and lawsuit have been dismissed.
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. 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. As a result, SDG&E is now participating in the arbitration as a claimant and respondent.
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. On July 18, 2014, the Montana Supreme Court determined that the parties’ contractual agreement to resolve any disputes in San Diego was mandatory, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial for January 22, 2016.
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 three of the seven lawsuits for an amount that is not significant.
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. In the second quarter of 2014, the municipality of Ensenada dismissed the administrative proceeding, which is subject to an administrative appeal, pending for resolution before the Administrative Court of Baja California. 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 also filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría de la 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 in March 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.
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.
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. RBS, our partner in the joint venture, was notified by the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigating value-added tax (VAT) refund claims made by various businesses in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactions by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid during 2009 because RBS 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 October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tier Tribunal. As a condition of the appeal, RBS was required to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax.
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, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.
SoCalGas has the responsibility for procuring natural gas for both SDG&E’s and SoCalGas’ core customers in a combined portfolio. SoCalGas buys natural gas under short-term and long-term contracts for this portfolio. Purchases are from various producing regions in the southwestern U.S., U.S. Rockies, and Canada and are primarily based on published monthly bid-week indices.
SoCalGas transports natural gas primarily under long-term firm interstate pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments with interstate pipeline companies for firm pipeline capacity under contracts that expire at various dates through 2028.
Sempra Natural Gas’ and Sempra Mexico’s businesses have various natural gas purchase agreements to fuel natural gas-fired power plants and capacity agreements for natural gas storage and transportation.
Sempra Natural Gas has an agreement for capacity on the Rockies Express pipeline through November 2019, as we discuss in Note 4. The capacity costs are offset by revenues from releases of the capacity contracted to third parties. Certain capacity release commitments totaling $22 million concluded during 2013, and contracting activity related to that capacity has not been sufficient to offset all of our capacity payments to Rockies Express. Including capacity released to others, Sempra Natural Gas’ obligation to Rockies Express for future capacity payments is expected to be $11 million in 2015, $14 million in each of 2016 and 2017, $34 million in 2018, and $67 million in 2019.
At December 31, 2014, the future minimum payments under existing natural gas contracts and natural gas storage and transportation contracts were
| FUTURE MINIMUM PAYMENTS – SEMPRA ENERGY CONSOLIDATED |
| (Dollars in millions) | | | | | | |
| | | Storage and | | | | |
| | | transportation | Natural gas(1) | Total(1) |
| 2015 | $ | 238 | $ | 194 | $ | 432 |
| 2016 | | 256 | | 152 | | 408 |
| 2017 | | 241 | | 152 | | 393 |
| 2018 | | 217 | | 121 | | 338 |
| 2019 | | 150 | | 4 | | 154 |
| Thereafter | | 241 | | 12 | | 253 |
| Total minimum payments | $ | 1,343 | $ | 635 | $ | 1,978 |
| (1) | Excludes amounts related to LNG purchase agreements as discussed below. |
| FUTURE MINIMUM PAYMENTS – SOCALGAS |
| (Dollars in millions) | | | | | | |
| | Transportation | Natural gas | Total |
| 2015 | $ | 127 | $ | 22 | $ | 149 |
| 2016 | | 128 | | 1 | | 129 |
| 2017 | | 113 | | 1 | | 114 |
| 2018 | | 92 | | 1 | | 93 |
| 2019 | | 48 | | 1 | | 49 |
| Thereafter | | 123 | | ― | | 123 |
| Total minimum payments | $ | 631 | $ | 26 | $ | 657 |
Total payments under natural gas contracts and natural gas storage and transportation contracts as well as payments to meet additional portfolio needs at Sempra Energy Consolidated and SoCalGas were:
| | Years ended December 31, |
| (Dollars in millions) | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 1,984 | $ | 1,680 | $ | 1,345 |
| SoCalGas | | 1,735 | | 1,464 | | 1,222 |
Sempra Natural Gas has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The agreement is priced using a predetermined formula based on natural gas market indices. Although this contract specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the contracts by Sempra Natural Gas. At December 31, 2014, the following LNG commitment amounts are based on if all cargoes under the contract were to be delivered:
| § | $7.6 billion in 2020 – 2029 |
The amounts above are based on forward prices of the index applicable to each contract from 2015 to 2024 and an estimated one percent escalation per year beyond 2024. The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreement. Actual LNG purchases in 2014, 2013 and 2012 have been significantly lower than the maximum amount possible due to the customer electing to divert most cargoes as allowed by the agreement.
Purchased-Power Contracts
For 2015, SDG&E expects to meet its customer power requirements from the following resource types:
| § | Long-term contracts: 35 percent (of which 30.2 percent is provided by renewable energy contracts expiring on various dates through 2041) |
| § | SDG&E-owned generation (including Palomar Energy Center, Miramar Energy Center, Desert Star Energy Center and Cuyamaca Peak Energy Plant) and tolling contracts (including OMEC): 57 percent |
| § | Spot market purchases: 8 percent |
Chilquinta Energía and Luz del Sur also have purchased-power contracts, expiring on various dates extending through 2027, which cover most of the consumption needs of the companies’ customers. These commitments are included under Sempra Energy Consolidated in the table below.
At December 31, 2014, the estimated future minimum payments under long-term purchased-power contracts were:
| FUTURE MINIMUM PAYMENTS – PURCHASED-POWER CONTRACTS |
| (Dollars in millions) |
| | | Sempra | | |
| | | Energy | | |
| | Consolidated | SDG&E |
| 2015 | $ | 674 | $ | 494 |
| 2016 | | 664 | | 484 |
| 2017 | | 687 | | 503 |
| 2018 | | 734 | | 505 |
| 2019 | | 734 | | 500 |
| Thereafter | | 7,363 | | 6,318 |
| Total minimum payments(1) | $ | 10,856 | $ | 8,804 |
| (1) | Excludes purchase agreements accounted for as capital leases and amounts related to Otay Mesa VIE, as it is consolidated by Sempra Energy and SDG&E. |
Payments on these contracts represent capacity charges and minimum energy purchases. SDG&E, Chilquinta Energía, and Luz del Sur are required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Excluding DWR-allocated contracts at SDG&E, total payments under purchased-power contracts were:
| | | Years ended December 31, |
| (Dollars in millions) | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 1,574 | $ | 1,377 | $ | 1,205 |
| SDG&E(1) | | 710 | | 570 | | 381 |
| (1) | Excludes DWR-allocated contracts. Under an operating agreement with the DWR that expired at the end of 2013, SDG&E acted as a limited agent on behalf of the DWR in the administration of energy contracts, including natural gas procurement functions under the DWR contracts allocated to SDG&E's customers. The commodity costs associated with these contracts are not included in SDG&E's or Sempra Energy's Consolidated Statements of Operations. |
Sempra Energy Consolidated, SDG&E and SoCalGas have operating leases on real and personal property expiring at various dates from 2015 through 2054. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from two percent to six percent at Sempra Energy Consolidated, four percent to six percent at SDG&E, and two percent to five percent at SoCalGas. The rentals payable under these leases may increase by a fixed amount each year or by a percentage of a base year, and most leases contain extension options that we could exercise.
The California Utilities have an operating lease agreement for future acquisitions of fleet vehicles with an aggregate maximum lease limit of $150 million, $134 million of which has been utilized as of December 31, 2014.
Rent expense for all operating leases totaled
| | Years ended December 31, |
| (Dollars in millions) | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated | $ | 78 | $ | 81 | $ | 74 |
| SDG&E | | 26 | | 23 | | 20 |
| SoCalGas | | 38 | | 31 | | 26 |
At December 31, 2014, the minimum rental commitments payable in future years under all noncancelable operating leases were as follows:
| FUTURE MINIMUM PAYMENTS – OPERATING LEASES |
| (Dollars in millions) | | | | | | |
| | Sempra | | |
| | Energy | | |
| | Consolidated | SDG&E | SoCalGas |
| 2015 | $ | 73 | $ | 24 | $ | 39 |
| 2016 | | 65 | | 24 | | 35 |
| 2017 | | 64 | | 22 | | 35 |
| 2018 | | 57 | | 18 | | 34 |
| 2019 | | 50 | | 16 | | 30 |
| Thereafter | | 271 | | 75 | | 156 |
| Total future minimum rental commitments | $ | 580 | $ | 179 | $ | 329 |
Power Purchase Agreements
SDG&E has three power purchase agreements with peaker plant facilities, two of which went into commercial operation in June 2010 and one of which went into commercial operation in 2014. All three are accounted for as capital leases. The entities that own the peaker plant facilities are VIEs of which SDG&E is not the primary beneficiary. As of December 31, 2014, capital lease obligations for these leases, each with a 25-year term, were valued at $233 million. SDG&E does not have any additional implicit or explicit financial responsibility related to these VIEs.
At December 31, 2014, the future minimum lease payments and present value of the net minimum lease payments under these capital leases for both Sempra Energy Consolidated and SDG&E were as follows:
| FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENTS |
| (Dollars in millions) |
| 2015 | | $ | 31 |
| 2016 | | | 31 |
| 2017 | | | 31 |
| 2018 | | | 31 |
| 2019 | | | 31 |
| Thereafter | | 520 |
| Total minimum lease payments(1) | | 675 |
| Less: estimated executory costs | | (137) |
| Less: interest(2) | | (305) |
| Present value of net minimum lease payments(3) | $ | 233 |
| (1) | This amount will be recorded over the lives of the leases as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs. |
| (2) | Amount necessary to reduce net minimum lease payments to present value at the inception of the leases. |
| (3) | Includes $4 million in Current Portion of Long-Term Debt and $229 million in Long-Term Debt on Sempra Energy’s and SDG&E’s Consolidated Balance Sheets at December 31, 2014. |
The annual amortization charge for the power purchase agreements was $3 million in 2014 and $2 million in each of 2013 and 2012.
The California Utilities entered into agreements in 2009 and 2010 to refinance existing fleet vehicles. These are capital leases and, at December 31, 2014, the related capital lease obligations were $2 million at Sempra Energy Consolidated, including $1 million at SDG&E and $1 million at SoCalGas. At December 31, 2013, the related capital lease obligations were $5 million at Sempra Energy Consolidated, including $3 million at SDG&E and $2 million at SoCalGas.
At December 31, 2014, the future minimum lease payments and present value of the net minimum lease payments under these capital leases are as follows:
| FUTURE MINIMUM PAYMENTS – CAPITAL LEASES |
| (Dollars in millions) |
| | Sempra | | |
| | Energy | | |
| | Consolidated | SDG&E | SoCalGas |
| Total minimum lease payments, all in 2015 | $ | 2 | $ | 1 | $ | 1 |
| Present value of net minimum lease payments(1) | $ | 2 | $ | 1 | $ | 1 |
| (1) | Excludes negligible amounts of interest. | | | | | | |
The 2014 annual depreciation charge for the utility fleet vehicles was $4 million at Sempra Energy Consolidated, including $2 million at SDG&E and $2 million at SoCalGas. The 2013 annual depreciation charge for the utility fleet vehicles was $7 million at Sempra Energy Consolidated, including $4 million at SDG&E and $3 million at SoCalGas. The 2012 annual depreciation charge for the utility fleet vehicles was $13 million at Sempra Energy Consolidated, including $7 million at SDG&E and $6 million at SoCalGas.
Headquarters Build-to-Suit Lease
In August 2013, Sempra Energy entered into a 25-year, build-to-suit lease for its future San Diego, California, headquarters. We expect to occupy the building in the second half of 2015, concurrent with the termination of the current headquarters lease. At December 31, 2014, future payments on the lease are as follows:
| FUTURE MINIMUM PAYMENTS – BUILD-TO-SUIT LEASE |
| (Dollars in millions) |
| 2015 | $ | 4 |
| 2016 | | 10 |
| 2017 | | 10 |
| 2018 | | 10 |
| 2019 | | 10 |
| Thereafter | | 267 |
| Total future payments | $ | 311 |
Construction and Development Projects
Sempra Energy Consolidated has various capital projects in progress in the United States, Mexico and South America. Sempra Energy’s total commitments under these projects are $877 million, requiring future payments of $721 million in 2015, $93 million in 2016, $46 million in 2017, $10 million in 2018, $1 million in 2019 and $6 million thereafter. The following is a summary by segment of contractual commitments and contingencies related to the construction projects.
SDG&E
At December 31, 2014, SDG&E has commitments to make future payments of $340 million for construction projects that include
| § | $130 million for the engineering, material procurement and construction costs primarily associated with the San Luis Rey Synchronous Condensor and Bay Boulevard Substation relocation projects; |
| § | $10 million related to nuclear fuel fabrication and other construction projects at SONGS; and |
| § | $200 million for infrastructure improvements for natural gas and electric transmission and distribution operations. |
SDG&E expects future payments under these contractual commitments to be $229 million in 2015, $57 million in 2016, $37 million in 2017, $10 million in 2018, $1 million in 2019 and $6 million thereafter.
SoCalGas
At December 31, 2014, SoCalGas has commitments to make future payments of $260 million for construction and infrastructure improvements for natural gas storage, transmission and distribution operations and pipeline integrity. The future payments under these contractual commitments are expected to be $218 million in 2015, $33 million in 2016, and $9 million in 2017.
Sempra South American Utilities
At December 31, 2014, Sempra South American Utilities has commitments to make future payments of $15 million for construction projects that include $3 million for the construction of the Santa Teresa hydroelectric power plant at Luz del Sur. The future payments under these contractual commitments are all expected to be made in 2015.
Sempra Mexico
At December 31, 2014, Sempra Mexico has commitments to make future payments of $244 million for contracts related to the construction of an approximately 500-mile natural gas transport pipeline network. The future payments under these contractual commitments are expected to be $241 million in 2015 and $3 million in 2016.
Sempra Natural Gas
At December 31, 2014, Sempra Natural Gas has commitments to make future payments of $18 million primarily for natural gas transportation projects. The future payments under these contractual commitments are all expected to be made in 2015.
At December 31, 2014, SDG&E and SoCalGas did not have any outstanding guarantees.
At December 31, 2014, Sempra Renewables has provided guarantees to its solar and wind farm joint ventures aggregating a maximum of $170 million with an associated aggregated carrying value of $2 million, primarily related to purchased-power agreements and engineering, procurement and construction contracts. In addition, Sempra Renewables has provided guarantees aggregating a maximum of $332 million with an associated aggregated carrying value of $12 million at December 31, 2014 to certain wind farm joint ventures for debt service and operation of the wind farms, which we discuss in Note 5.
Sempra Energy entered into completion guarantees related to the financing of the Cameron LNG project, as we discuss in Note 4.
In connection with the completion of the Sunrise Powerlink project in 2012, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink. The future payments for these contractual commitments are expected to be approximately $3 million per year, subject to escalation of 2 percent per year, for 58 years. At December 31, 2014, the present value of these future payments of $116 million has been recorded as a regulatory asset as the amounts represent a cost that will be recovered from customers in the future, and the related liability was $116 million.
In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC (Citizens), a subsidiary of Citizens Energy Corporation. For this payment, under the terms of the agreement with Citizens, SDG&E will provide Citizens with access to a segment of the Sunrise Powerlink transmission line known as the Border-East transmission line equal to 50 percent of the transfer capacity of this portion of the line for a period of 30 years. After the 30-year contract term, the transfer capability will revert to SDG&E. SDG&E will amortize deferred revenues from the use of the transfer capability over the 30-year term, and depreciation for 50 percent of the Border-East transmission line segment will be accelerated from an estimated 58-year life to 30 years.
In February 2013, Sempra Natural Gas entered into a long-term operations and maintenance agreement for its remaining block of the Mesquite Power natural gas-fired power plant, which expires in 2033. The total cost associated with this agreement is estimated to be approximately $33 million. The minimum future payments for this contractual commitment are expected to be $2 million each year in 2015 through 2019 and $23 million thereafter. We provide additional information about Mesquite Power in Note 3.
Additional consideration for a 2006 comprehensive legal settlement with the State of California to resolve the Continental Forge litigation included an agreement that, for a period of 18 years beginning in 2011, Sempra Natural Gas would sell to the California Utilities, subject to annual CPUC approval, up to 500 million cubic feet (MMcf) per day of regasified LNG from Sempra Mexico’s Energía Costa Azul facility that is not delivered or sold in Mexico at the California border index minus $0.02 per MMBtu. There are no specified minimums required, and to date, we have not been required to deliver any natural gas pursuant to this agreement.
Our operations are subject to federal, state and local environmental laws. We also are subject to regulations related to hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. These laws and regulations require that we investigate and correct the effects of the release or disposal of materials at sites associated with our past and our present operations. These sites include those at which we have been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and similar state laws.
In addition, we are required to obtain numerous governmental permits, licenses and other approvals to construct facilities and operate our businesses. The related costs of environmental monitoring, pollution control equipment, cleanup costs, and emissions fees are significant. Increasing national and international concerns regarding global warming and mercury, carbon dioxide, nitrogen oxide and sulfur dioxide emissions could result in requirements for additional pollution control equipment or significant emissions fees or taxes that could adversely affect Sempra Natural Gas and Sempra Mexico. The California Utilities’ costs to operate their facilities in compliance with these laws and regulations generally have been recovered in customer rates.
We generally capitalize the significant costs we incur to mitigate or prevent future environmental contamination or extend the life, increase the capacity, or improve the safety or efficiency of property used in current operations. The following table shows our capital expenditures (including construction work in progress) in order to comply with environmental laws and regulations:
| CAPITAL EXPENDITURES FOR ENVIRONMENTAL ISSUES |
| (Dollars in millions) |
| | | Years ended December 31, |
| | | 2014 | 2013 | 2012 |
| Sempra Energy Consolidated(1) | $ | 45 | $ | 31 | $ | 92 |
| SDG&E | | 23 | | 13 | | 77 |
| SoCalGas | | 21 | | 15 | | 12 |
| (1) | In cases of non-wholly owned affiliates, includes only our share. |
Fluctuations at SDG&E and Sempra Energy Consolidated from 2012 to 2013 were primarily due to mitigation activities on the Sunrise Powerlink project, which was placed into service in June 2012. Fluctuations from 2013 to 2014 were primarily due to increased project activities during 2014, including PSEP-related projects at both SDG&E and SoCalGas and the Aliso Canyon turbine replacement project at SoCalGas. We have not identified any significant environmental issues outside the United States.
At the California Utilities, costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the probability that these costs will be recovered in rates.
The environmental issues currently facing us or resolved during the last three years include (1) investigation and remediation of the California Utilities’ manufactured-gas sites, (2) cleanup of third-party waste-disposal sites used by the California Utilities at sites for which we have been identified as a PRP and (3) mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS. The requirements for enhanced fish protection and restoration of 150 acres of coastal wetlands for the SONGS mitigation are in process and include a 150-acre artificial reef that was dedicated in 2008 and continues in process to meet California Coastal Commission (CCC) acceptance requirements. It is anticipated that the CCC will require expansion of the reef in 2015, as the existing reef may be too small to consistently meet the performance standard. The table below shows the status at December 31, 2014, of the California Utilities’ manufactured-gas sites and the third-party waste-disposal sites for which we have been identified as a PRP:
| STATUS OF ENVIRONMENTAL SITES |
| |
| | | # Sites | # Sites |
| | | completed(1) | in process |
| SDG&E | | | | |
| Manufactured-gas sites | | 3 | | ― |
| Third-party waste-disposal sites | | 2 | | 3 |
| SoCalGas | | | | |
| Manufactured-gas sites | | 39 | | 3 |
| Third-party waste-disposal sites | | 5 | | 2 |
| (1) | There may be on-going compliance obligations for completed sites, such as regular inspections, adherence to land use covenants and water quality monitoring. |
We record environmental liabilities at undiscounted amounts when our liability is probable and the costs can be reasonably estimated. In many cases, however, investigations are not yet at a stage where we can determine whether we are liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the costs. Estimates of our liability are further subject to uncertainties such as the nature and extent of site contamination, evolving cleanup standards and imprecise engineering evaluations. We review our accruals periodically and, as investigations and cleanup proceed, we make adjustments as necessary. The following table shows our accrued liabilities for environmental matters at December 31, 2014:
| ACCRUED LIABILITIES FOR ENVIRONMENTAL MATTERS |
| (Dollars in millions) |
| | | | Waste | Former fossil- | Other | |
| | | Manufactured- | disposal | fueled power | hazardous | |
| | | gas sites | sites (PRP)(1) | plants | waste sites | Total |
| SDG&E(2)(3) | $ | ― | $ | 0.3 | $ | 6.1 | $ | 0.7 | $ | 7.1 |
| SoCalGas(3) | | 23.8 | | 0.1 | | ― | | 0.1 | | 24.0 |
| Other | | 2.0 | | 1.1 | | ― | | 10.2 | | 13.3 |
| Total Sempra Energy | $ | 25.8 | $ | 1.5 | $ | 6.1 | $ | 11.0 | $ | 44.4 |
| (1) | Sites for which we have been identified as a Potentially Responsible Party. |
| (2) | Does not include SDG&E’s liability for SONGS marine mitigation. |
| (3) | This includes $7 million at SDG&E and $24 million at SoCalGas related to hazardous waste sites subject to the Hazardous Waste Collaborative mechanism approved by the CPUC in 1994. This mechanism permits California’s IOUs, including the California Utilities, to recover in rates 90 percent of hazardous waste cleanup costs and related third-party litigation costs, and 70 percent of the related insurance-litigation expenses for certain sites. In addition, the California Utilities have the opportunity to retain a percentage of any recoveries from insurance carriers and other third parties to offset the cleanup and associated litigation costs not recovered in rates. |
We expect to pay the majority of these accruals over the next three years. In connection with the issuance of operating permits, SDG&E and the other owners of SONGS previously reached an agreement with the CCC to mitigate the damage to the marine environment caused by the cooling-water discharge from SONGS during its operation. SONGS’ early retirement, described in Note 13, does not reduce SDG&E’s mitigation obligation. At December 31, 2014, SDG&E’s share of the estimated mitigation costs remaining to be spent through 2050 is $20 million, which is recoverable in rates.
We discuss renewable energy requirements in Note 14 and greenhouse gas regulation in Note 1.
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 Nuclear Electric Insurance Limited (NEIL), a mutual insurance company. 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.
U.S. 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. SDG&E will seek recovery for these costs from the appropriate sources, including, but not limited to, SDG&E’s Nuclear Decommissioning Trust. SDG&E will also continue to support Edison in its pursuit of legal claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel.
In June 2010, the United States Court of Federal Claims issued a decision granting Edison and the SONGS co-owners damages of approximately $142 million to recover costs incurred through December 31, 2005 for the DOE’s failure to meet its obligation to begin accepting spent nuclear fuel from SONGS. Edison received payment from the federal government in the amount of the damage award in November 2011. In January 2012, Edison refunded SDG&E $28 million for its respective share of the damage award paid. SDG&E recorded a $10 million reduction of nuclear power expenses, a $15 million reduction of its nuclear decommissioning balancing account and a $3 million reduction in nuclear plant. Edison, as operating agent, filed a lawsuit against the DOE in the Court of Federal Claims in December 2011 seeking damages for the period from January 1, 2006 to December 31, 2010 for the DOE’s failure to meet its obligation to begin accepting spent nuclear fuel. In September 2014, Edison updated their claim to include another $84 million for costs incurred from January 2011 to December 2013.
CONCENTRATION OF CREDIT RISK
We maintain credit policies and systems to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile, Peru, southwest Alabama, and Hattiesburg, Mississippi.
When they become operational, projects owned or partially owned by Sempra Natural Gas, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers and customers to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects.
NOTE 16. SEGMENT INFORMATION
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. |
| 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, 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 Natural Gas also owns and operates the Mesquite Power plant, a natural gas-fired electric generation asset. In October 2014, Sempra Natural Gas entered into a definitive agreement to sell the remaining 625-MW block of Mesquite Power. The sale is expected to close in the first half of 2015, subject to obtaining third-party consents as we discuss in Note 3. |
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.
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 Consolidated Statements of Operations and Consolidated Balance Sheets. We provide information about our equity method investments by segment in Note 4. Amounts labeled as “All other” in the following tables consist primarily of parent organizations.
| SEGMENT INFORMATION |
| (Dollars in millions) |
| | Years ended December 31, |
| | 2014 | 2013 | 2012 |
| REVENUES | | | | | | | | | | | | |
| SDG&E | $ | 4,329 | 39 | % | $ | 4,066 | 39 | % | $ | 3,694 | 38 | % |
| SoCalGas | | 3,855 | 35 | | | 3,736 | 35 | | | 3,282 | 34 | |
| Sempra South American Utilities | | 1,534 | 14 | | | 1,495 | 14 | | | 1,441 | 15 | |
| Sempra Mexico | | 818 | 8 | | | 675 | 6 | | | 605 | 6 | |
| Sempra Renewables | | 35 | ― | | | 82 | 1 | | | 68 | 1 | |
| Sempra Natural Gas | | 979 | 9 | | | 908 | 9 | | | 931 | 10 | |
| Adjustments and eliminations | | (3) | ― | | | (2) | ― | | | (2) | ― | |
| Intersegment revenues(1) | | (512) | (5) | | | (403) | (4) | | | (372) | (4) | |
| Total | $ | 11,035 | 100 | % | $ | 10,557 | 100 | % | $ | 9,647 | 100 | % |
| INTEREST EXPENSE | | | | | | | | | | | | |
| SDG&E | $ | 202 | | | $ | 197 | | | $ | 173 | | |
| SoCalGas | | 69 | | | | 69 | | | | 68 | | |
| Sempra South American Utilities | | 33 | | | | 27 | | | | 32 | | |
| Sempra Mexico | | 17 | | | | 17 | | | | 8 | | |
| Sempra Renewables | | 5 | | | | 23 | | | | 22 | | |
| Sempra Natural Gas | | 111 | | | | 116 | | | | 98 | | |
| All other | | 241 | | | | 241 | | | | 251 | | |
| Intercompany eliminations | | (124) | | | | (131) | | | | (159) | | |
| Total | $ | 554 | | | $ | 559 | | | $ | 493 | | |
| INTEREST INCOME | | | | | | | | | | | | |
| SDG&E | $ | ― | | | $ | 1 | | | $ | ― | | |
| Sempra South American Utilities | | 14 | | | | 14 | | | | 15 | | |
| Sempra Mexico | | 4 | | | | 2 | | | | 2 | | |
| Sempra Renewables | | 1 | | | | 20 | | | | 6 | | |
| Sempra Natural Gas | | 115 | | | | 88 | | | | 55 | | |
| All other | | 1 | | | | ― | | | | 4 | | |
| Intercompany eliminations | | (113) | | | | (105) | | | | (58) | | |
| Total | $ | 22 | | | $ | 20 | | | $ | 24 | | |
| DEPRECIATION AND AMORTIZATION | | | | | | | | | | | | |
| SDG&E | $ | 530 | 46 | % | $ | 494 | 44 | % | $ | 490 | 45 | % |
| SoCalGas | | 431 | 37 | | | 383 | 35 | | | 362 | 33 | |
| Sempra South American Utilities | | 55 | 5 | | | 59 | 5 | | | 56 | 5 | |
| Sempra Mexico | | 64 | 6 | | | 63 | 6 | | | 62 | 6 | |
| Sempra Renewables | | 5 | ― | | | 21 | 2 | | | 16 | 1 | |
| Sempra Natural Gas | | 61 | 5 | | | 81 | 7 | | | 93 | 9 | |
| All other | | 10 | 1 | | | 12 | 1 | | | 11 | 1 | |
| Total | $ | 1,156 | 100 | % | $ | 1,113 | 100 | % | $ | 1,090 | 100 | % |
| INCOME TAX EXPENSE (BENEFIT) | | | | | | | | | | | | |
| SDG&E | $ | 270 | | | $ | 191 | | | $ | 190 | | |
| SoCalGas | | 139 | | | | 116 | | | | 79 | | |
| Sempra South American Utilities | | 58 | | | | 67 | | | | 78 | | |
| Sempra Mexico | | 5 | | | | 60 | | | | 73 | | |
| Sempra Renewables | | (44) | | | | (19) | | | | (63) | | |
| Sempra Natural Gas | | (20) | | | | 40 | | | | (157) | | |
| All other | | (108) | | | | (89) | | | | (141) | | |
| Total | $ | 300 | | | $ | 366 | | | $ | 59 | | |
| SEGMENT INFORMATION (Continued) |
| (Dollars in millions) |
| | | At December 31 or for the years ended December 31, |
| | | 2014 | 2013 | 2012 |
| EARNINGS (LOSSES) | | | | | | | | | | | | |
| SDG&E(2) | $ | 507 | 44 | % | $ | 404 | 41 | % | $ | 484 | 56 | % |
| SoCalGas(3) | | 332 | 29 | | | 364 | 37 | | | 289 | 34 | |
| Sempra South American Utilities | | 172 | 15 | | | 153 | 15 | | | 164 | 19 | |
| Sempra Mexico | | 192 | 16 | | | 122 | 12 | | | 157 | 18 | |
| Sempra Renewables | | 81 | 7 | | | 62 | 6 | | | 61 | 7 | |
| Sempra Natural Gas | | 50 | 4 | | | 64 | 6 | | | (241) | (28) | |
| All other | | (173) | (15) | | | (168) | (17) | | | (55) | (6) | |
| Total | $ | 1,161 | 100 | % | $ | 1,001 | 100 | % | $ | 859 | 100 | % |
| ASSETS | | | | | | | | | | | | |
| SDG&E | $ | 16,296 | 41 | % | $ | 15,377 | 41 | % | $ | 14,744 | 40 | % |
| SoCalGas | | 10,461 | 26 | | | 9,147 | 25 | | | 9,071 | 25 | |
| Sempra South American Utilities | | 3,379 | 9 | | | 3,531 | 10 | | | 3,310 | 9 | |
| Sempra Mexico | | 3,488 | 9 | | | 3,246 | 9 | | | 2,591 | 7 | |
| Sempra Renewables | | 1,338 | 3 | | | 1,219 | 3 | | | 2,439 | 7 | |
| Sempra Natural Gas | | 6,436 | 16 | | | 7,200 | 19 | | | 5,145 | 14 | |
| All other | | 895 | 2 | | | 838 | 2 | | | 818 | 2 | |
| Intersegment receivables | | (2,561) | (6) | | | (3,314) | (9) | | | (1,619) | (4) | |
| Total | $ | 39,732 | 100 | % | $ | 37,244 | 100 | % | $ | 36,499 | 100 | % |
| EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT | | | | | | | | | | | | |
| SDG&E | $ | 1,100 | 35 | % | $ | 978 | 38 | % | $ | 1,237 | 42 | % |
| SoCalGas | | 1,104 | 35 | | | 762 | 30 | | | 639 | 22 | |
| Sempra South American Utilities | | 174 | 6 | | | 200 | 8 | | | 183 | 6 | |
| Sempra Mexico | | 325 | 10 | | | 371 | 14 | | | 45 | 2 | |
| Sempra Renewables | | 190 | 6 | | | 176 | 7 | | | 717 | 24 | |
| Sempra Natural Gas | | 212 | 7 | | | 83 | 3 | | | 131 | 4 | |
| All other | | 18 | 1 | | | 2 | ― | | | 4 | ― | |
| Total | $ | 3,123 | 100 | % | $ | 2,572 | 100 | % | $ | 2,956 | 100 | % |
| GEOGRAPHIC INFORMATION | | | | | | | | | | | | |
| Long-lived assets(4): | | | | | | | | | | | | |
| United States | $ | 24,183 | 84 | % | $ | 22,654 | 84 | % | $ | 22,698 | 85 | % |
| Mexico | | 2,821 | 10 | | | 2,597 | 9 | | | 2,219 | 8 | |
| South America | | 1,746 | 6 | | | 1,784 | 7 | | | 1,790 | 7 | |
| Total | $ | 28,750 | 100 | % | $ | 27,035 | 100 | % | $ | 26,707 | 100 | % |
| | | | | | | | | | | | | | |
| Revenues(5): | | | | | | | | | | | | |
| United States | $ | 8,774 | 79 | % | $ | 8,478 | 80 | % | $ | 7,711 | 80 | % |
| South America | | 1,534 | 14 | | | 1,495 | 14 | | | 1,441 | 15 | |
| Mexico | | 727 | 7 | | | 584 | 6 | | | 495 | 5 | |
| Total | $ | 11,035 | 100 | % | $ | 10,557 | 100 | % | $ | 9,647 | 100 | % |
| (1) | Revenues for reportable segments include intersegment revenues of $10 million, $69 million, $91 million and $342 million for 2014, $10 million, $70 million, $91 million and $232 million for 2013, and $8 million, $46 million, $108 million and $210 million for 2012 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively. |
| (2) | For 2013, amount is after preferred dividends and call premium on preferred stock. For 2012, amount is after preferred dividends. |
| (3) | After preferred dividends. |
| (4) | Includes net property, plant and equipment and investments. |
| (5) | Amounts are based on where the revenue originated, after intercompany eliminations. |
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)
We provide quarterly financial information for Sempra Energy Consolidated, SDG&E and SoCalGas below:
| SEMPRA ENERGY |
| (In millions, except per share amounts) |
| | | Quarters ended |
| | | March 31 | June 30 | September 30 | December 31 |
| 2014 | | | | | | | | |
| Revenues | $ | 2,795 | $ | 2,678 | $ | 2,815 | $ | 2,747 |
| Expenses and other income | $ | 2,408 | $ | 2,302 | $ | 2,368 | $ | 2,433 |
| | | | | | | | | | |
| Net income | $ | 266 | $ | 292 | $ | 383 | $ | 321 |
| Earnings attributable to Sempra Energy | $ | 247 | $ | 269 | $ | 348 | $ | 297 |
| | | | | | | | | | |
| Basic per-share amounts(1): | | | | | | | | |
| Net income | $ | 1.09 | $ | 1.19 | $ | 1.56 | $ | 1.31 |
| Earnings attributable to Sempra Energy | $ | 1.01 | $ | 1.10 | $ | 1.41 | $ | 1.21 |
| Weighted average common shares outstanding | | 245.3 | | 245.7 | | 246.1 | | 246.4 |
| | | | | | | | | | |
| Diluted per-share amounts(1): | | | | | | | | |
| Net income | $ | 1.07 | $ | 1.17 | $ | 1.53 | $ | 1.28 |
| Earnings attributable to Sempra Energy | $ | 0.99 | $ | 1.08 | $ | 1.39 | $ | 1.18 |
| Weighted average common shares outstanding | | 249.7 | | 250.1 | | 250.8 | | 251.3 |
| 2013 | | | | | | | | |
| Revenues | $ | 2,650 | $ | 2,651 | $ | 2,551 | $ | 2,705 |
| Expenses and other income | $ | 2,298 | $ | 2,353 | $ | 2,119 | $ | 2,357 |
| | | | | | | | | | |
| Net income | $ | 178 | $ | 267 | $ | 323 | $ | 320 |
| Earnings attributable to Sempra Energy | $ | 178 | $ | 245 | $ | 296 | $ | 282 |
| | | | | | | | | | |
| Basic per-share amounts(1): | | | | | | | | |
| Net income | $ | 0.73 | $ | 1.10 | $ | 1.32 | $ | 1.31 |
| Earnings attributable to Sempra Energy | $ | 0.73 | $ | 1.00 | $ | 1.21 | $ | 1.15 |
| Weighted average common shares outstanding | | 243.3 | | 243.6 | | 244.1 | | 244.4 |
| | | | | | | | | | |
| Diluted per-share amounts(1): | | | | | | | | |
| Net income | $ | 0.72 | $ | 1.07 | $ | 1.29 | $ | 1.28 |
| Earnings attributable to Sempra Energy | $ | 0.72 | $ | 0.98 | $ | 1.19 | $ | 1.13 |
| Weighted average common shares outstanding | | 247.5 | | 248.5 | | 249.3 | | 249.9 |
| (1) | Earnings per share are computed independently for each of the quarters and therefore may not sum to the total for the year. |
| |
Revenues and Expenses and Other Income increased in each of the first three quarters in 2014 compared to 2013 partly due to higher natural gas prices, offset by lower volumes at SoCalGas. In the fourth quarter of 2014 compared to 2013, the impact on Revenues and Expenses and Other Income from lower volumes more than offset the impact from higher natural gas prices. In the first and fourth quarters of 2014 compared to 2013, the lower volumes were primarily due to a decrease in the demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013.
In each of the quarters of 2014 compared to the same periods in 2013, Revenues and Expenses and Other Income increased from higher cost of electric fuel and purchased power at SDG&E primarily due to the incremental purchase of renewable energy at higher prices.
In the third quarter of 2014, Net Income and Earnings Attributable to Sempra Energy included $25 million tax benefit due to the release of a Louisiana valuation allowance against a deferred tax asset associated with Cameron LNG developments.
Expenses and Other Income, Net Income and Earnings Attributable to Sempra Energy for the first, second and third quarters of 2014 included $9 million, $11 million and $14 million, respectively, of AFUDC related to equity associated with the construction of the Sonora natural gas pipeline in Mexico.
In the first quarter of 2013, Expenses and Other Income were favorably impacted by $74 million and Net Income and Earnings Attributable to Sempra Energy were favorably impacted by $44 million due to the sale of one 625-MW block of the 1,250-MW Mesquite Power natural gas-fired power plant, as we discuss in Note 3.
Net Income and Earnings Attributable to Sempra Energy for the first quarter of 2013 were negatively impacted by higher operating expenses at the California Utilities due to the delay in the CPUC decision on the 2012 GRC until the second quarter of 2013.
Revenues and Expenses and Other Income for the third quarter of 2013 were lower compared to the first, second and fourth quarters of 2013 due to lower cost of natural gas.
Net Income and Earnings Attributable to Sempra Energy for the first, second, third and fourth quarters of 2014 included $12 million, $12 million, $8 million and $6 million, respectively, of income tax expense for repatriation of current year foreign earnings. In the first quarter of 2013, Net Income and Earnings Attributable to Sempra Energy included $63 million income tax expense resulting from a corporate reorganization in connection with the IEnova stock offerings.
In the second quarter of 2013, Revenues included $131 million and Net Income and Earnings Attributable to Sempra Energy included $106 million favorable impacts from the retroactive application of the 2012 GRC for the period from January 2012 to March 2013 at the California Utilities.
In the second quarter of 2013, Expenses and Other Income were negatively impacted by $200 million and Net Income and Earnings Attributable to Sempra Energy were negatively impacted by $119 million due to the early retirement of SONGS, as we discuss in Note 13.
We discuss quarterly fluctuations related to SDG&E and SoCalGas below.
| SDG&E |
| (Dollars in millions) |
| | Quarters ended |
| | March 31 | June 30 | September 30 | December 31 |
| 2014 | | | | | | | | |
| Operating revenues | $ | 987 | $ | 1,063 | $ | 1,233 | $ | 1,046 |
| Operating expenses | | 766 | | 821 | | 957 | | 826 |
| Operating income | $ | 221 | $ | 242 | $ | 276 | $ | 220 |
| | | | | | | | | |
| Net income | $ | 101 | $ | 129 | $ | 169 | $ | 128 |
| Earnings attributable to noncontrolling interest | | (2) | | (6) | | (12) | | ― |
| Earnings attributable to common shares | $ | 99 | $ | 123 | $ | 157 | $ | 128 |
| 2013 | | | | | | | | |
| Operating revenues | $ | 939 | $ | 1,064 | $ | 1,063 | $ | 1,000 |
| Operating expenses | | 771 | | 939 | | 800 | | 774 |
| Operating income | $ | 168 | $ | 125 | $ | 263 | $ | 226 |
| | | | | | | | | |
| Net income | $ | 81 | $ | 73 | $ | 139 | $ | 142 |
| Losses (earnings) attributable to noncontrolling interest | | 11 | | (7) | | (5) | | (23) |
| Earnings | | 92 | | 66 | | 134 | | 119 |
| Call premium on preferred stock | | ― | | ― | | (3) | | ― |
| Dividends on preferred stock | | (1) | | (1) | | (2) | | ― |
| Earnings attributable to common shares | $ | 91 | $ | 65 | $ | 129 | $ | 119 |
| |
In each of the quarters of 2014 compared to the same periods in 2013, SDG&E’s Operating Revenues and Operating Expenses included increases from higher cost of electric fuel and purchased power primarily due to the incremental purchase of renewable energy at higher prices.
Net Income and Earnings for the first quarter of 2013 were negatively impacted by higher operating expenses due to the delay in the CPUC decision on the 2012 GRC until the second quarter of 2013.
SDG&E’s Operating Revenues in the second quarter of 2013 included $90 million and Net Income and Earnings included $69 million favorable impacts from the retroactive application of the 2012 GRC for the period from January 2012 to March 2013.
In the second quarter of 2013, Operating Expenses were negatively impacted by $200 million and Net Income and Earnings were negatively impacted by $119 million due to the early retirement of SONGS, as we discuss in Note 13.
| SOCALGAS |
| (Dollars in millions) |
| | Quarters ended |
| | March 31 | June 30 | September 30 | December 31 |
| 2014 | | | | | | | | |
| Operating revenues | $ | 1,085 | $ | 917 | $ | 855 | $ | 998 |
| Operating expenses | | 956 | | 795 | | 702 | | 881 |
| Operating income | $ | 129 | $ | 122 | $ | 153 | $ | 117 |
| | | | | | | | | |
| Net income | $ | 78 | $ | 81 | $ | 98 | $ | 76 |
| Dividends on preferred stock | | ― | | (1) | | ― | | ― |
| Earnings attributable to common shares | $ | 78 | $ | 80 | $ | 98 | $ | 76 |
| 2013 | | | | | | | | |
| Operating revenues | $ | 983 | $ | 904 | $ | 807 | $ | 1,042 |
| Operating expenses | | 900 | | 725 | | 652 | | 920 |
| Operating income | $ | 83 | $ | 179 | $ | 155 | $ | 122 |
| | | | | | | | | |
| Net income | $ | 46 | $ | 119 | $ | 102 | $ | 98 |
| Dividends on preferred stock | | ― | | (1) | | ― | | ― |
| Earnings attributable to common shares | $ | 46 | $ | 118 | $ | 102 | $ | 98 |
SoCalGas’ Operating Revenues and Operating Expenses increased in each of the first three quarters in 2014 compared to 2013 primarily due to higher natural gas prices, offset by lower volumes. In the fourth quarter of 2014 compared to 2013, the impact on Operating Revenues and Operating Expenses from lower volumes more than offset the impact from higher natural gas prices. In the first and fourth quarters of 2014 compared to 2013, the lower volumes were primarily due to a decrease in the demand for natural gas primarily from a warmer winter in 2014 compared to the same period in 2013.
Net Income and Earnings in the fourth quarter of 2014 compared to 2013 were impacted by lower income tax expenses in 2013 primarily related to resolution of prior years’ income tax items and higher flow-through deductions.
Net Income and Earnings in the first quarter of 2013 were negatively impacted by $12 million from higher operating expenses due to the delay in the CPUC decision on the 2012 GRC until the second quarter of 2013.
In the second quarter of 2013, Operating Revenues included $41 million and Net Income and Earnings included $37 million favorable impacts from the retroactive application of the 2012 GRC for the period from January 2012 to March 2013.
| GLOSSARY | | | |
| | | | |
| | | | |
| 2010 Tax Act | Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 | | CPSD | Consumer Protection and Safety Division, now known as the Safety and Enforcement Division |
| 2012 Tax Act | American Taxpayer Relief Act of 2012 | | CPUC | California Public Utilities Commission |
| 2014 Tax Act | Tax Increase Prevention Act of 2014 | | CRE | Comisión Reguladora de Energía (Energy Regulatory Commission) (Mexico) |
| AB | Assembly Bill | | CRRs | Congestion revenue rights |
| AFUDC | Allowance for funds used during construction | | CWIP | Construction work in progress |
| AMI | Advanced metering infrastructure | | DA | Direct Access |
| AOCI | Accumulated other comprehensive income (loss) | | DCE | Decommissioning cost estimate |
| ARO | Asset retirement obligation | | DOE | U.S. Department of Energy |
| ASLB | Atomic Safety and Licensing Board | | DWR | California Department of Water Resources |
| ASU | Accounting Standards Update | | Ecogas | Ecogas México, S. de R.L. de C.V. |
| Bay Gas | Bay Gas Storage Company, Ltd. | | Edison | Southern California Edison Company |
| Bcf | Billion cubic feet | | EIA | Environmental impact authorization |
| Black-Scholes model | Black-Scholes option-pricing model | | EIR/EIS | Environmental impact report/Environmental impact statement |
| BMV | La Bolsa Mexicana de Valores, S.A.B. de C.V. (Mexican Stock Exchange) | | Eletrans | Eletrans, collectively for Eletrans S.A. and Eletrans II S. A. |
| CAL | Confirmatory Action Letter | | EMA | Energy Management Agreement |
| Cal Fire | California Department of Forestry and Fire Protection | | EPC | Engineering, procurement and construction |
| California Utilities | San Diego Gas & Electric Company and Southern California Gas Company | | EPS | Earnings per common share |
| Cameron LNG | Cameron LNG, LLC | | ERRA | Energy Resource Recovery Account |
| Cameron LNG Holdings | Cameron LNG Holdings, LLC | | ESOP | Employee stock ownership plan |
| CARE | California Alternate Rates for Energy | | ESP | Energy Service Provider |
| CCC | California Coastal Commission | | FERC | Federal Energy Regulatory Commission |
| CCM | Cost of capital adjustment mechanism | | Final 2012 GRC Decision | Final CPUC decision on 2012 General Rate Case |
| CFE | Comisión Federal de Electricidad (Federal Electricity Commission) (Mexico) | | FTA | Free Trade Agreement |
| CFTC | U.S. Commodity Futures Trading Commission | | FTC | Federal Trade Commission |
Chilquinta Energía | Chilquinta Energía S.A. and its subsidiaries | | Gazprom | Gazprom Marketing & Trading Mexico |
| Citizens | Citizens Sunrise Transmission, LLC | | GCIM | Gas cost incentive mechanism |
| CLF | Chilean Unidad de Fomento | | GHG | Greenhouse gas |
| CNE | Comisión Nacional de Energía (National Energy Commission) (Chile) | | GRC | General Rate Case |
| CNF | Cleveland National Forest | | HMRC | United Kingdom's Revenue and Customs Department |
| ConEdison Development | Consolidated Edison Development | | HRA | Health Reimbursement Account |
| Cox | Cox Communications | | IEnova | Infraestructura Energética Nova, S.A.B. de C.V. |
| CPCN | Certificate of Public Convenience and Necessity | | IFMP | Irradiated fuel management plan |
| GLOSSARY (CONTINUED) | | |
| | | | |
| | | | | |
| IFRS | International Financial Reporting Standards | | NEM | Net energy metering |
| IOUs | Investor-owned utilities | | NERC | North American Electric Reliability Corporation |
| IRS | Internal Revenue Service | | NEXI | Nippon Export and Investment Insurance |
| ISFSI | Independent spent fuel storage installation | | NOL | Net operating loss |
| ISO | California Independent System Operator, also known as CAISO | | NRC | Nuclear Regulatory Commission |
| ITC | Investment tax credits | | NYK | Nippon Yusen Kabushiki Kaisha |
| JBIC | Japan Bank for International Cooperation | | OCI | Other comprehensive income (loss) |
| JP Morgan | J.P. Morgan Chase & Co. | | OII | Order Instituting Investigation |
| KMI | Kinder Morgan, Inc. | | OMEC | Otay Mesa Energy Center |
| KMP | Kinder Morgan Energy Partners L.P. | | OMEC LLC | Otay Mesa Energy Center LLC |
| kV | Kilovolt | | ORA | Office of Ratepayer Advocates (formerly the Division of Ratepayer Advocates or DRA) |
| LA Storage | LA Storage, LLC | | OSINERGMIN | Organismo Supervisor de la Inversión en Energía y Minería (Energy and Mining Investment Supervisory Body) (Peru) |
| Liberty | Liberty Gas Storage, LLC | | Otay Mesa VIE | Otay Mesa Energy Center LLC |
| LIFO | Last-in first-out | | OTC | Over-the-counter |
| LNG | Liquefied natural gas | | PBOP | Other postretirement benefit plans |
| Luz del Sur | Luz del Sur S.A.A. and its subsidiaries | | PBOP plan trusts | Other postretirement benefit plan trusts |
| Luzlinares | Luzlinares S.A. | | PCB | Polychlorinated Biphenyl |
| MBFC | Mississippi Business Finance Corporation | | PCRB | Pollution Control Revenue Bonds |
| Mcf | Thousand cubic feet | | PE | Pacific Enterprises |
| MHI | Mitsubishi Heavy Industries | | PEMEX | Petróleos Mexicanos (Mexican state-owned oil company) |
| MHI Collectively | Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. | | PG&E | Pacific Gas and Electric Company |
| Mississippi Hub | Mississippi Hub, LLC | | PPA | Power purchase agreement |
| MMBtu | Million British thermal units (of natural gas) | | PRP | Potentially Responsible Party |
| MMcf | Million cubic feet | | PSDAR | Post-shutdown decommissioning activities report |
| Mobile Gas | Mobile Gas Service Corporation | | PSEP | Pipeline Safety Enhancement Plan |
| MOU | Memorandum of understanding | | PTC | Production tax credit |
| MSUP | Master Special Use Permit | | RBS | The Royal Bank of Scotland plc |
| Mtpa | Million tonnes per annum | | RBS SEE | RBS Sempra Energy Europe |
| MW | Megawatt | | RBS Sempra Commodities | RBS Sempra Commodities LLP |
| MWh | Megawatt hour | | RECs | Renewable energy certificates |
| NDT | Nuclear Decommissioning Trusts | | REX | Rockies Express pipeline |
| NEIL | Nuclear Electric Insurance Limited | | Rockies Express | Rockies Express Pipeline LLC |
| GLOSSARY (CONTINUED) | | |
| | | | |
| | | | | |
| ROE | Return on equity | | Tangguh PSC | Tangguh PSC Contractors |
| ROR | Rate of return | | Tax Reform Bill | 2014 Chilean Tax Reform Bill |
| RPS | Renewables Portfolio Standard | | TCAP | Triennial Cost Allocation Proceeding |
| RSAs | Restricted stock awards | | Tecnored | Tecnored S.A. |
| RSUs | Restricted stock units | | Tecsur | Tecsur S.A. |
| S&P | Standard & Poor's | | TIMP | Transmission Integrity Management Program |
| SAESA | Sociedad Austral de Electricidad Sociedad Anónima | | TO3 | Electric Transmission Formula Rate |
| SB | Senate Bill | | TO4 | Electric Transmission Formula Rate |
| SDG&E | San Diego Gas & Electric Company | | Trust | ESOP Trust |
| SEDATU | Secretaría de Desarrollo Agrario, Territorial y Urbano | | TURN | The Utility Reform Network |
| SEMARNAT | Mexican environmental protection agency | | UC | University of California |
| SFP | Secondary financial protection | | USFS | United States Forest Service |
| SGRP | Steam Generator Replacement Project | | U.S. GAAP | Accounting principles generally accepted in the United States of America |
| Shell | Shell México Gas Natural | | VaR | Value at Risk |
| SoCalGas | Southern California Gas Company | | VAT | Value added tax |
| SONGS | San Onofre Nuclear Generating Station | | VEBA | Voluntary Employee Beneficiary Association |
| SONGS OII | CPUC’s Order Instituting Investigation (OII) into the SONGS Outage | | VIE | Variable interest entity |
| SPPR Group | Southwest Public Power Resources Group | | VREP | Voluntary Retirement Enhancement Program |
| SRP | Salt River Project Agricultural Improvement and Power District | | Williams | Williams Midstream Natural Gas Liquids, Inc. |
| SWPL | Southwest Powerlink | | Willmut Gas | Willmut Gas Company |
| Tallgrass | Tallgrass Energy Partners, L.P. | | | |
