We provide information concerning rates and regulation applicable to our utilities in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Notes 1, 13 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.

We discuss environmental issues affecting us in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. You should read the following additional information in conjunction with those discussions.

The CPUC’s Hazardous Waste Collaborative mechanism allows California’s IOUs to recover hazardous waste cleanup costs for certain sites, including those related to certain Superfund sites. This mechanism permits 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. 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.

The electric and natural gas industries are subject to increasingly stringent air-quality and greenhouse gas standards, such as those established by the United States Environmental Protection Agency (EPA),EPA, the CARB and SCAQMD. The California Utilities generally recover in rates the costs to comply with these standards. We discuss greenhouse gas standards and credits further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

At December 31, each company has the following number of employees:

Field employees and some clerical and technical employees at SDG&E are represented by the International Brotherhood of Electrical Workers. Provisions of the collective bargaining agreement covering wages and working conditions for these employees are in effect through August 31, 2020 (subject to wage renegotiation on September 1, 2019). For these same employees, the agreement covering pension and savings plan benefits is in effect through October 1, 2017 and the agreement covering health and welfare benefits is in effect through December 31, 2016.2017. At December 31, 2015,2016, 29 percent of SDG&E employees are covered by these agreements.

Field, technical and administrative employees at Luz del Sur are represented by the Unified Trade Union of Electricity Workers of Lima and Callao, and the Trade Union of Employees of Electrolima.various labor unions. In February 2016,January 2017, two collective bargaining agreements were signed covering these employees, which will also be extended to 138141 nonrepresented employees. It will cover wages, working conditions and other benefit plans, and will be in effect from January 1, 20162017 through December 31, 2016.

Field, technical and administrative employees at Chilquinta Energía are represented by Labor Union Number 1 Chilquinta Energía, Labor Union Number 2 Chilquinta Energía, Litoral Labor Union, Luzlinares Labor Union, Tecnored Labor Union Number 1, Negotiating Group Luzparral and Negotiating Group Casablanca.under various collective bargaining agreements with different labor unions. The collective bargaining agreements for employees represented by these unions and negotiating groups cover wages, hours, working conditions and medical and other benefit plans and are in effect through 2016expire between 2017 and 2019.

Professional employees at Chilquinta Energía are represented by the Professional Union. The collective bargaining agreement for these employees covers wages, hours, working conditions and medical and other benefit plans and is in effect through July 2, 2017.

At December 31, 2015,2016, Sempra South American Utilities has a total of 1,3781,140 employees in Peru, of whom 2423 percent are covered under a labor agreement, and 1,4411,464 employees in Chile, of whom 4145 percent are covered under labor agreements.

At December 31, 2015,2016, Sempra Mexico has 639883 employees, 64 percent of whom are covered by various collective bargaining agreements with different labor unions. The collective bargaining agreements are subject to renegotiation on an annual basis with respect to wages, and otherwise on a bi-annual basis.

Sempra Energy’s ability to pay dividends and meet its debt obligations depends almost entirely on cash flows from its subsidiaries and, in the short term, its ability to raise capital from external sources. In the long term, cash flows from the subsidiaries depend on their ability to generate operating cash flows in excess of their own expenditures, common and preferred stock dividends (if any), and long-term debt obligations. In addition, the subsidiaries are separate and distinct legal entities that are not obligated to pay dividends and could be precluded from making such distributions under certain circumstances, including, without limitation, as a result of legislation, regulation, court order, contractual restrictions or in times of financial distress.

Our businesses are capital intensive and we rely significantly on long-term debt to fund a portion of our capital expenditures and refundrepay outstanding debt, and on short-term borrowings to fund a portion of day-to-day business operations.

Limitations on the availability of credit and increases in interest rates or credit spreads may materially adversely affect our businesses, cash flows, results of operations, financial condition and/or prospects, as well as our ability to meet contractual and other commitments. In difficult credit market environments, we may find it necessary to fund our operations and capital expenditures at a higher cost or we may be unable to raise as much funding as we need to support new business activities. This could cause us to reduce capital expenditures and could increase our cost of servicing debt, both of which could significantly reduce our short-term and long-term profitability.

Such incidents could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to us. Any such incident could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.

In recent years, the regulatory environment that applies to the electric power and natural gas industries has undergone significant changes, on the federal, state and local levels. These changes have affected the nature of these industries and the manner in which their participants conduct their businesses. These changes are ongoing, and we cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on our businesses. Moreover, existing regulations, laws and tariffs may be revised or reinterpreted, and new regulations, laws and tariffs may be adopted or become applicable to us and our facilities. Special tariffs may also be imposed on components used in our businesses that could increase costs.

Our operations are subject to rules relating to transactions among the California Utilities and other Sempra Energy businesses. These rules are commonly referred to as “affiliate rules,” which primarily impact commodity and commodity-related transactions. These businesses could be materially adversely affected by changes in these rules or to their interpretations, or by additional CPUC or FERC rules that further restrict our ability to sell electricity or natural gas to, or to trade with, the California Utilities and with each other. Affiliate rules also could require us to obtain prior approval from the CPUC before entering into any such transactions with the California Utilities. Any such restrictions on or approval requirements for transactions among affiliates could materially adversely affect the LNG terminals, natural gas pipelines, electric generation facilities, or other operations of our subsidiaries, which could have a material adverse effect on our businesses, results of operations and/or prospects.

All of our existing and planned development projects require multiple approvals. The acquisition, construction, ownership and operation of LNG terminals; natural gas pipelines and distribution and storage facilities; electric generation, transmission and distribution facilities; and propane and ethane systems require numerous permits, licenses, franchise agreements, certificates and other approvals from federal, state, local and foreign governmental agencies. Once received, approvals may be subject to litigation, and projects may be delayed or approvals reversed or modified in litigation. In addition, permits, licenses, franchise agreements, certificates, and other approvals may be modified, rescinded or fail to be extended by one or more of the governmental agencies and authorities that oversee our businesses. SoCalGas’ franchise agreements forwith the City of Los Angeles and Los Angeles County, where the Aliso Canyon facility is located, are due to expire in 2016 and 2017, respectively.2017. If there is a delay in obtaining any required regulatory approvals or failure to obtain or maintain any required approvals or to comply with any applicable laws or regulations, we may not be able to constructprecluded from constructing or operate ouroperating facilities, or we may be forced to incur additional costs. Further, accidents beyond our control may cause us to violate the terms of conditional use permits, causing delays in projects. Any such delay or failure to obtain or maintain necessary permits, licenses, certificates and other approvals could cause our sales to materially decline, and/or our costs to materially increase, and otherwise materially adversely affect our businesses, cash flows, financial condition, results of operations and/or prospects.

Our businesses are subject to extensive federal, state, local and foreign statutes, rules and regulations and mandates relating to environmental protection, including, air quality, water quality and usage, wastewater discharge, solid waste management, hazardous waste disposal and remediation, conservation of natural resources, wetlands and wildlife, renewable energy resources, climate change and greenhouse gas, or GHG, emissions. We are required to obtain numerous governmental permits, licenses, certificates and other approvals to construct and operate our businesses. Additionally, to comply with these legal requirements, we must spend significant amounts on environmental monitoring, pollution control equipment, mitigation costs and emissions fees. The California Utilities may be materially adversely affected if these additional costs for projects are not recoverable in rates. In addition, we may be ultimately responsible for all on-site liabilities associated with the environmental condition of our LNG terminals,terminals; natural gas transmission, distribution and storage facilities,facilities; electric generation, transmission and distribution facilitiesfacilities; and other energy projects and properties,properties; regardless of when the liabilities arose and whether they are known or unknown.unknown, which exposes us to risks arising from contamination at our former or existing facilities or with respect to offsite waste disposal sites that have been used in our operations. In the case of our California and other regulated utilities, some of these costs may not be recoverable in rates. Our facilities, including those in our joint ventures, are subject to laws and regulations protecting migratory birds, which have recently been the subject of increased enforcement activity with respect to wind farms. Failure to comply with applicable environmental laws, regulations and permits may subject our businesses to substantial penalties and fines and/or significant curtailments of our operations, which could materially adversely affect our cash flows and/or results of operations.

In addition, existing and future laws, orders and regulations regarding mercury, nitrogen and sulfur oxides, particulates, methane or other emissions could result in requirements for additional monitoring, pollution monitoring and control equipment, safety practices or emission fees, taxes or penalties that could materially adversely affect our results of operations and/or cash flows. Moreover, existing rules and regulations may be interpreted or revised in ways that may materially adversely affect our results of operations and/or cash flows.

Sempra Energy and its subsidiaries are defendants in numerous lawsuits and arbitration proceedings. We have spent, and continue to spend, substantial amounts of money and time defending these lawsuits and proceedings, and in related investigations and regulatory proceedings. We discuss pending proceedings in Note 15 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. The uncertainties inherent in lawsuits, arbitrations and other legal proceedings make it difficult to estimate with any degree of certainty the costs and effects of resolving these matters. In addition, juries have demonstrated a willingness to grant large awards, including punitive damages, in personal injury, product liability, property damage and other claims. Accordingly, actual costs incurred may differ materially from insured or reserved amounts and may not be recoverable in whole or in part in rates from our customers, which in each case could materially adversely affect our businesses, cash flows, results of operations and/or financial condition.

To reduce financial exposure related to commodity price fluctuations, we may enter into contracts to hedge our known or anticipated purchase and sale commitments, inventories of natural gas and LNG, natural gas storage and pipeline capacity and electric generation capacity. As part of this strategy, we may use forward contracts, physical purchase and sales contracts, futures, financial swaps, and options. We do not hedge the entire exposure to market price volatility of our assets or our contract positions, and the coverage will vary over time. To the extent we have unhedged positions, or if our hedging strategies do not work as planned, fluctuating commodity prices could have a material adverse effect on our results of operations, cash flows and/or financial condition.

Several of our businesses have entered into and have in place collective bargaining agreements with different labor unions. Our collective bargaining agreements are generally negotiated on a company-by-company basis. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our businesses, results of operations and/or cash flows.

In the ordinary course of business, Sempra Energy and its subsidiaries collect and retain sensitive information, including personal identification information about customers and employees, customer energy usage and other information. The theft, damage or improper disclosure of sensitive electronic data can subject us to penalties for violation of applicable privacy laws, subject us to claims from third parties, require compliance with notification and monitoring regulations, and harm our reputation.

Finally, as seen with recent cyber-attacks around the world, the goal of a cyber-attack may be primarily to inflict large-scale harm on a company and the places where it operates. Any such cyber-attack could cause widespread disruptions to our operating and administrative systems, including the destruction of critical information and programming, that could materially adversely affect our business operations and the integrity of the power grid, and/or release confidential information about our company and our customers, employees and other constituents.

The CPUC conducts various reviews and audits of utility performance, safety standards and practices, compliance with CPUC regulations and standards, affiliate relationships and other matters. These reviews and audits may result in disallowances, fines and penalties that could materially adversely affect our financial condition, results of operations and/or cash flows. SoCalGas and SDG&E may be subject to penalties or fines related to their operation of natural gas pipelines and storage and, for SDG&E, electric operations, under regulations concerning natural gas pipeline safety and citation programs concerning both gas and electric safety, which could have a material adverse effect on their results of operations, financial condition and/or cash flows. We discuss various CPUC proceedings relating to the California Utilities’ rates, costs, incentive mechanisms, and performance-based regulation in Notes 13, 14 and 1415 of the Notes to Consolidated Financial Statements and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

The CPUC periodically approves the California Utilities’ rates based on authorized capital expenditures, operating costs, including income taxes, and an authorized rate of return on investment. Delays by the CPUC on decisions authorizing recovery or authorizations for less than full recovery may adversely affect the working capital and financial condition of each of the California Utilities. If the California Utilities receive an adverse CPUC decision and/or actual capital expenditures and/or operating costs were to exceed the amounts approved by the CPUC, our results of operations, financial condition, cash flows and/or prospects could be materially adversely affected. Reductions in key benchmark interest rates may trigger automatic adjustment mechanisms which would reduce the California Utilities’ authorized rates of return, changes in which could materially adversely affect their results of operations, financial condition, cash flows and/or prospects.

The CPUC applies performance-based measures and mechanisms to all California utilities. Under these, earnings potential over authorized base margins is tied to achieving or exceeding specific performance and operating goals, and reductions in authorized base margins are tied to not achieving specific performance and operating goals. At both of the California Utilities, the areas that are currently eligible for performance mechanisms are operational activities designated by the CPUC and energy efficiency programs; at SDG&E, electric reliability performance; and, at SoCalGas, natural gas procurement and unbundled natural gas storage and system operator hub services. Although the California Utilities have received incentive awards in the past, there can be no assurance that they will receive awards in the future, or that any future awards earned would be in amounts comparable to prior periods. Additionally, if the California Utilities fail to achieve certain minimum performance levels established under such mechanisms, they may be assessed financial disallowances, penalties and fines which could have a material adverse effect on their results of operations, financial condition and/or cash flows.

The FERC regulates electric transmission rates, the transmission and wholesale sales of electricity in interstate commerce, transmission access, the rates of return on investments in electric transmission assets, and other similar matters involving SDG&E.

The California Utilities may be materially adversely affected by new legislation, regulations, decisions, orders or interpretations of the CPUC, the FERC or other regulatory bodies. In addition, existing legislation or regulations may be revised or reinterpreted. New, revised or reinterpreted legislation, regulations, decisions, orders or interpretations could change how the California Utilities operate, could affect their ability to recover various costs through rates or adjustment mechanisms, or could require them to incur substantial additional expenses.

Pursuant to a stipulation and order and in response to claims made pursuant to lawsuits described below,by the Los Angeles County Superior Court (Superior Court), SoCalGas has been providingprovided temporary relocation support to residents in the nearby community who request it. In addition, SoCalGas has been providing air filtration and purification systems to those residents inrequested it before the nearby community requesting them. As a result of receiving the confirmation from DOGGR that the SS25 well was permanently sealed, SoCalGas started winding down its temporary relocation support. Subjectat significant expense to SoCalGas. Following the permanent sealing of the well and the completion of the Los Angeles County Department of Public Health’s (DPH) indoor testing of certain exceptions,homes in the periodPorter Ranch community, which concluded that indoor conditions did not present a long-term health risk and that it was safe for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, concluded on February 25, 2016. This deadline has been challenged and is subject to a recent court order extending such period for an additional 22 days for certain residents. SoCalGas has appealed this order extending the support period. Additionally, residents who have been placed in rental housing will have through the agreed term of their leases to return home. In addition,home, the Superior Court issued an order in May 2016 ruling that currently relocated residents be given the choice to request residence cleaning prior to returning home, with such cleaning to be performed according to the DPH’s proposed protocol and at SoCalGas’ expense. SoCalGas also intends to mitigatecompleted the GHG emissionscleaning program, and the relocation program ended in July 2016.

Apart from the actualSuperior Court order, in May 2016 the DPH also issued a directive that SoCalGas professionally clean (in accordance with the proposed protocol prepared by the DPH) the homes of all residents located within the Porter Ranch Neighborhood Council boundary, or who participated in the relocation program, or who are located within a five mile radius of the Aliso Canyon natural gas released.

The total costs incurred to remediate and stop the leak and to mitigate environmental and local community impacts will beof the leak are significant and may increase, and to the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

In addition effective February 5, 2016,to the DOGGR amendedlawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and directors, and four shareholder derivative actions alleging breach of fiduciary duties have been filed against certain officers and directors of Sempra Energy and/or SoCalGas. Three complaints have also been filed by public entities, including the California CodeAttorney General, the SCAQMD and the County of Regulations to require all underground natural gas storage facility operators,Los Angeles. These complaints seek various remedies, including SoCalGas, to take further steps to help ensureinjunctive relief, abatement of the safetypublic nuisance, civil penalties, payment of their gas storage operations. Additional hearings in the state legislaturecost of a longitudinal health study, and money damages, as well as punitive damages and attorneys’ fees. In February 2017, SoCalGas entered into a settlement agreement with variousthe SCAQMD under which SoCalGas will pay $8.5 million and SCAQMD will dismiss its complaint and petition for dismissal of a stipulated abatement order issued by its Hearing Board. Separately, in February 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other regulatory agenciesremedies for alleged failure to provide timely notice of the leak and for allegedly violating certain California Health and Safety Code provisions. On November 29, 2016, the court approved a settlement between SoCalGas and the District Attorney’s Office whereby SoCalGas agreed to plead no contest to a misdemeanor for the alleged failure to provide timely notice of the leak and to spend approximately $4.3 million on reimbursement of government agency expenses, operational commitments, and fines and penalties, in exchange for the dismissal of the remaining counts. Certain individuals residing near Aliso Canyon who objected to the settlement have been or are expectedfiled a notice of appeal of the judgment, as well as a petition asking the Superior Court to set aside the November 29, 2016 order and grant them restitution.

Additional litigation may be scheduled, additional legislation has been proposedfiled against us in the state legislature,future related to the Aliso Canyon incident or our responses thereto. For a more detailed description of the governmental investigations and additional laws, orders, rulescivil and regulations may be adopted.

The costs to complyof defending against the civil and criminal lawsuits, cooperating with the various laws, orders, rulesinvestigations, and regulations arising out of this incidentany damages, restitution, and civil and criminal fines, costs and other penalties, if awarded or imposed, could be significant and to the extent not covered by insurance (including any costs in excess of applicable policy limits), or if there were to be significant delays in customer rates,receiving insurance recoveries, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.

Natural gas withdrawn from storage is important for ensuring service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer.summer and heating needs in the winter. Aliso Canyon, with a storage capacity of 86 Bcf (which represents 63 percent of SoCalGas’ natural gas storage inventory capacity), is the largest SoCalGas storage facility and an important element of SoCalGas’ delivery system, serving millions of homes and businesses across Southern California. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity.system. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, pursuant to orders by DOGGR and the Governor, and SB 380. Limited withdrawals of natural gas from Aliso Canyon have been made in 2017 to augment natural gas supplies during critical demand periods. In November 2016, SoCalGas submitted a request to DOGGR seeking authorization to resume injection operations at the Aliso Canyon storage facility. In accordance with the Governor’s OrderSB 380, DOGGR held public meetings on February 1 and subject2, 2017 to contrary CPUC reliability-based direction, SoCalGas will continue this moratoriumreceive public comment on further injections until the completion of a review, utilizing independent experts, of the safety of each of theDOGGR’s findings from its gas storage wells and air quality in the surrounding communities and an evaluation by an independent panel of scientific and medical experts on whether additional measures are needed to protect public health. We are also currently reviewing the recently released DOGGRwell safety review requirements associated with returningand proposed pressure limits for the Aliso Canyon natural gas storage facility. The public comment period has expired. It remains for DOGGR to an active injection/withdrawal status. issue its safety determination, after which the CPUC must concur with DOGGR’s determination, before injections at the facility can resume.

If thisthe Aliso Canyon facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the Aliso Canyon facility, and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At December 31, 2015,2016, the Aliso Canyon facility has a net book value of $243$531 million, excluding $162including $217 million of construction work in progress for the project to construct a new compression station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations for the period in which it is recorded. Higher operating costs and additional capital expenditures incurred by SoCalGas may not be recoverable in customer rates, which may have a material adverse effect on ourand SoCalGas’ and Sempra Energy’s results of operations, cash flows and financial condition.

Pending the outcome of various regulatory agency evaluations of natural gas pipeline safety regulations, practices and procedures, Sempra Energy, including the California Utilities, may incur substantial incremental expense and capital investment associated with their natural gas pipeline operations and investments. The California Utilities filed a comprehensive planimplementation plans with the CPUC to test or replace natural gas transmission pipelines located in populated areas that either have not been pressure tested or lack sufficient documentation of a pressure test, to enhance existing valve infrastructure and to retrofit pipelines to allow for the use of in-line inspection technology, referred to as SoCalGas’ and SDG&E’s Pipeline Safety Enhancement Plan (PSEP). The California Utilities’ total estimated cost for Phase I (the 10-year period from 2012 to 2022) of the two-phase PSEP was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E). These cost estimates may continue to change over time to reflect the development of more detailed estimates, actual costs experienced as portions of the work are completed, and changes in scope.

In June 2014, the CPUC issued a final decision approving the utilities’ modelplan 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. In October 2014, the California Utilities filed a petition for modificationfuture, certain PSEP costs may be subject to recovery as determined by separate regulatory filings with the CPUC, requesting authority to recover PSEP costs from customers, subject to refundincluding GRC filings.

If the CPUC or its staff determine that either of SDG&E’s or SoCalGas’ operations and practices are not in compliance with applicable safety standards and operating procedures, the corrective or mitigation actions required to be in conformance, if not sufficiently funded in customer rates, and any penalties imposed could materially adversely affect that company’s cash flows, financial condition, results of operations and prospects.

Due to current rate structures and state policies, customers who self-generate their own power using eligible renewable resources (primarily solar installations) currently do not pay their proportionate cost of maintaining and operating the electric transmission and distribution system, subject to certain limitations, while they still receive power from the system when their self-generation is inadequate to meet their electricity needs. The proportionate costs not paid by NEM customers are paid (i.e., subsidized) by consumers not participating in NEM. In addition, the continuing increase of self-generated solar, other forms of self-generation and other local off-the-grid sources of power adversely impacts the reliability of the electric transmission and distribution system.

In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing NEM program pursuant to the provisions of AB 327, which required the CPUC to establish a revised NEM tariff or similar program by December 31, 2015.327. The NEM program was originally established in 1995 and 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 theUnder NEM, program. Under NEM,qualifying customer-generators receive a full retail rate for the energy they generate that is fed back to the utility’s power grid. This occurs during times when the customer’s generation exceeds their own energy usage. In addition, if a NEM customer generates any electricity over the annual measurement period that exceeds its annual consumption, they receive compensation at a rate equal to a wholesale energy price.

Electric utilities in California are experiencing increasing deployment of distributed energy resources, such as solar, energy storage, energy efficiency and demand response technologies. This growth will eventually require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity and increase the grid’s capacity to interconnect distributed energy resources. The CPUC is conducting proceedings: to evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of distributed energy resources; to consider future grid modernization and grid reinforcement investments; to evaluate if traditional grid investments can be deferred by distributed energy resources, and if feasible, what, if any, compensation would be preferableappropriate; and to recovering these costs from customers not participatingclarify the role of the electric distribution grid operator. These proceedings may result in NEM. If NEM self-generating installations were to increase substantially between 2016 and 2019 when more significant reforms are to take effect, the rate structure adopted by the CPUCnew regulations, policies and/or operational changes that could have a material adverse effect onmaterially adversely affect SDG&E’s business, cash flows, financial condition, results of operations and/or prospects.

In addition, the FERC has adopted changes that have opened transmission development to competition from independent developers, allowing such developers to compete with incumbent utilities for the construction and distribution system, such failureoperation of transmission facilities. These changes could have a material adverse effect onmaterially adversely affect SDG&E’s business cash flows, financial condition, results of operations and/orand prospects.

SDG&E is seeking to recover in rates its reasonably incurred costs of resolving 2007 wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Through December 31, 2015,2016, SDG&E’s payments for claimsclaim 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. At December 31, 2015,2016, Sempra Energy’s and SDG&E’s Consolidated Balance Sheets included assets of $362$352 million in Other Regulatory Assets (long-term), of which $359 million is related to CPUC-regulated operations and $3 million is related to FERC-regulated operations, for these costs incurred and the estimated resolution of pending claims.

Recovery of these costs in rates will require future regulatory approvals.approval. SDG&E will continue to assess the likelihood, amount and timing of such recoveries in rates. Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E would 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, 2015,2016, the resulting after-tax charge against earnings would have been up to approximately $213$208 million.

In addition, SDG&E maintains nuclear decommissioning trusts for the purpose of providing funds to decommission SONGS. Trust assets have been generally invested in equity and debt securities, which are subject to significant market fluctuations. A decline in the market value of trust assets or an adverse change in the law regarding funding requirements for decommissioning trusts could increase the funding requirements for these trusts, which in each case may not be fully recoverable in rates. Furthermore, CPUC approval is required in order to make withdrawals from these trusts. CPUC approvals may lag cash expenditures, and approval for certain expenditures may be denied by the CPUC altogether if the CPUC determines that the expenditures are unreasonable. Finally, decommissioning may be materially more expensive than we currently anticipate and therefore decommissioning costs may exceed the amounts in the trust funds. RecoveryRate recovery for those overruns would require CPUC approval, which may not occur.

The occurrence of any of these events could result in a substantial reduction in our expected recovery and have a material adverse effect on SDG&E’s and Sempra Energy’s businesses, cash flows, financial condition, results of operations and/or prospects.

We buy energy-related commodities from time to time, for LNG terminals or power plants to satisfy contractual obligations with customers, in regional markets and other competitive markets in which we compete. Our revenues and results of operations could be materially adversely affected if the prevailing market prices for natural gas, LNG, electricity or other commodities that we buy change in a direction or manner not anticipated and for which we had not provided adequately through purchase or sale commitments or other hedging transactions.

The FERC has jurisdiction over wholesale power and transmission rates, independent system operators, and other entities that control transmission facilities or that administer wholesale power sales in some of the markets in which we operate. The FERC may impose additional price limitations, bidding rules and other mechanisms, or terminate existing price limitations from time to time. Any such action by the FERC may result in prices for electricity changing in an unanticipated direction or manner and, as a result, may have a material adverse effect on our businesses, cash flows, results of operations and/or prospects.

If we are unable to complete a development project or if we have substantial delays or cost overruns, this could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.

The operation of existing and future facilities also involves many risks, including the breakdown or failure of electric generation, transmission and distribution facilities, or natural gas regasification, liquefaction and storage facilities or other equipment or processes, labor disputes, fuel interruption, environmental contamination and operating performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, regasification, liquefaction, storage, transmission and distribution systems. The occurrence of any of these events could lead to our facilities being idled for an extended period of time or our facilities operating well below expected capacity levels, which may result in lost revenues or increased expenses, including higher maintenance costs and penalties. Such occurrences could materially adversely affect our businesses, financial condition, cash flows, results of operations and/or prospects.

With respect to our project to add LNG export capability at the Cameron LNG facility, the Cameron LNG Holdings, LLC joint venture (Cameron LNG JV) has begunis building an LNG export facility consisting of three liquefaction trains designed to a total nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. 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 total cost of the facility, including the cost of our original regasification facility contributed to the joint venture plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash exceeding our current estimates. The majority of the incremental investment in the joint venture will be project-financed and the balance provided by the project partners. Any failure by the project partners to make their required investments on a timely basis could result in project delays and could materially adversely affect the development of the project. In addition, Sempra Energy has entered into completion guarantees under which it has guaranteed a maximum $3.7of $3.9 billion of principal amount ofrelated to the project financing for the project.and financing-related agreements. These guarantees terminate upon Cameron LNG JV’s achieving “financial completion” of the initial three-train liquefaction project, including all three trains achieving commercial operation and meeting certain operational performance tests. If, due to the joint venture’s failure to satisfy the financial completion criteria, we are required to repay some or all of the $3.7$3.9 billion principal amount of project debt under our completion guarantees, any such repayments could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.

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. Cameron LNG JV has a turnkey EPC contract with a joint venture contractor comprised of subsidiaries of Chicago Bridge & Iron Company N.V. and Chiyoda Corporation, who are jointly and severally liable for performance under the contract. If the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG JV wouldmay be required to engage a substitute contractor, which would result in project delays and increased costs, which could be significant. The construction of this facility requires a large and specialized work force, necessary equipment and materials, and sophisticated engineering. There can be no assurance that Cameron LNG JV’s contractor will not encounter delays due to disruptions in obtaining the necessary equipment and materials, inability to field the necessary workforce, weather conditions, or engineering issues that were not contemplated. In October 2016, Cameron LNG JV received an indication from the EPC contractor that the respective in-service dates for each train may be delayed. Any such construction delays will defer a portion of the 2018 and 2019 earnings anticipated from the Cameron LNG project. As construction progresses, Cameron LNG JV may decide or be forced to submit change orders to the contractor that could result in longer construction periods and higher construction costs or both. In addition, weather conditions, new regulation,regulations, labor disputes, breakdown or failure of equipment and litigation such as the lawsuit filed by the Sierra Club and Gulf Restoration Network challenging the June 19, 2014 FERC order that approved the construction of the Cameron LNG liquefaction project, could substantially delay the project. As we do not control Cameron LNG JV, we are dependent on reaching a consensus with one or more of our joint venture partners to resolve a variety of issues that could transpire. The inability to timely resolve issues, including construction issues, could cause substantial delays to the completion of this project. A substantial delay could result in cost overruns, substantially postpone the earnings we anticipate deriving from this facility, and require additional cash investments by us and our joint venture partners. The anticipated cost of this project is based on a number of assumptions that may prove incorrect, and the ultimate cost could significantly exceed the current estimate of approximately $7 billion of incremental investment, excluding capitalized interest and other financing costs. These risks could have a material adverse effect on our business, results of operations, cash flows, financial condition, and/or prospects.

In addition to the three-train Cameron LNG liquefaction facility described above, we are looking at several other LNG export terminal development opportunities, including a greenfield project in Port Arthur, Texas, a brownfield project at our existing Energía Costa Azul regasification facility in Baja California, Mexico and an expansion of up to two additional liquefaction trains to the Cameron liquefaction facility. Each of these contemplated projects faces numerous risks and must overcome significant hurdles before we can proceed with construction. Common to all of these projects is the risk that an extended decline in current and forward projections of crude oil prices could reduce the demand for natural gas in some sectors and 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. Such reduction in natural gas demand could also occur from higher penetration of coal in new power generation, which could also lead to increased competition among the LNG suppliers for the declining LNG demand. Oil prices at certain moderate levels could also make LNG projects in other parts of the world still feasible and competitive with LNG projects from North America, thus increasing supply and the competition for the available LNG demand. A decline in natural gas prices outside the United States (which in many foreign countries are based on the price of crude oil) may also materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).

Expansion of the Cameron LNG liquefaction facility beyond the first three trains is subject to certain restrictions and conditions under the joint venture project financing agreements, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from the project lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all of the partners, including with respect to the equity investment obligation of each partner. One of the partners indicated to Sempra Energy and the other partners that it does not intend to invest additional capital in Cameron LNG JV with respect to the expansion. As a result, discussions among the partners have occurred, and we are considering a variety of options to attempt to move the expansion project forward. These activities have contributed to delays in developing firm pricing information and securing customer commitments. In light of these developments, we cannot assure you that the various consents required for expansion of the Cameron LNG project will be obtained.

Furthermore, there are a number of potential new projects under construction or in the process of development by various project developers in North America, in addition to ours, and given the projected global demand for LNG, the vast majority of these projects likely will not be completed. With respect to our Port Arthur, Texas project, this is a greenfield site, and therefore it may not have the advantages often associated with brownfield sites. The Energía Costa Azul facility in Mexico is subject to on-going land and permitting disputes that could make project financing difficult as well as finding suitable partners and customers. In addition, while we have completed the regulatory process for an LNG export facility in the U.S., the regulatory process in Mexico and the overlay of U.S. regulations for natural gas exports to an LNG export facility in Mexico are not well developed. There can be no assurance that such a facility could be permitted and constructed without facing significant legal challenges and uncertainties, which in turn could make project financing, as well as finding suitable partners and customers, difficult. Finally, Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the facility, making the decision to pursue a new liquefaction facility dependent in part on whether the investment in a new liquefaction facility would, over the long term, be more beneficial than continuing to supply regasification services under our existing contracts.

Several states have adopted or are considering adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but federal agencies have asserted regulatory authority over certain hydraulic fracturing activities. For example, the EPA issued permitting guidance in February 2014 under the federal Safe Drinking Water Act (SDWA) for hydraulic fracturing activities involving the use of diesel fuels. In April 2015, the EPA issued a proposed rule that would prevent the discharge of hydraulic fracturing wastewater into publicly owned treatment works, and in March 2015, the Bureau of Land Management of the U.S. Department of the Interior adopted rules imposing new requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure of hydraulic fracturing chemicals, as well as wellbore integrity and handling of flowback water. In addition, the U.S. Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews that have been conducted or are underway on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate or even ban such activities. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.

The markets in which we operate are characterized by numerous strong and capable competitors, many of whom may have extensive and diversified developmental and/or operating experience (including both domestic and international) and financial resources similar to or greater than ours. Further, in recent years, the natural gas pipeline, storage and LNG market segments have been characterized by strong and increasing competition both with respect to winning new development projects and acquiring existing assets. In Mexico, despite the commissioning of many new energy infrastructure projects by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) and other governmental agencies in connection with energy reforms, competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that we will be successful in bidding for new development opportunities in the U.S., Mexico or South America. In addition, as noted above, there are a number of potential new LNG liquefaction projects under construction or in the process of being developed by various project developers in North America, including our contemplated new projects, and given the projected global demand for LNG, the vast majorityit is likely that most of these projects likely will not be completed. Finally, as existing contracts expire at our natural gas storage assets in the Gulf Coast region, we compete with other facilities for storage customers asthat could continue to support the existing contracts expirebook value of these assets, and for anchor customers that could support development of new capacity. These competitive factors could have a material adverse effect on our business, results of operations, cash flows and/or prospects.

The Energía Costa Azul LNG facility and the Cameron LNG facility (within the Cameron LNG JV) have entered into long-term capacity agreements with a limited number of counterparties at each facility. Under these agreements, customers pay capacity reservation and usage fees to receive, store and regasify the customers’ LNG. We also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified for sale to other parties. The long-term supply agreement contracts are expected to reduce our exposure to changes in natural gas prices through corresponding natural gas sales agreements or by tying LNG supply prices to prevailing natural gas market price indices. If the counterparties, customers or suppliers to one or more of the key agreements for the LNG facilities were to fail to perform or become unable to meet their contractual obligations on a timely basis, it could have a material adverse effect on our results of operations, cash flows and/or prospects.

For the three-train liquefaction facility currently under construction, Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. (formerly GDF SUEZ S.A.) and affiliates of Mitsubishi Corporation and Mitsui & Co. Ltd., that subscribe for the full nameplate capacity of the facility. If the counterparties to occur during the first quarterthese tolling agreements were to fail to perform or become unable to meet their contractual obligations to Cameron LNG JV on a timely basis, it could have a material adverse effect on our results of 2017.

Sempra Mexico’s and Sempra Natural Gas’LNG & Midstream’s ability to enter into or replace existing long-term firm capacity agreements for their natural gas pipeline operations are dependent on demand for and supply of LNG and/or natural gas from their transportation customers, which may include our LNG facilities. A significant sustained decrease in demand for and supply of LNG and/or natural gas from such customers could have a material adverse effect on our businesses, results of operations, cash flows and/or prospects.

Our natural gas storage assets include operational and development assets at Bay Gas Storage Company, Ltd. (Bay Gas) in Alabama and Mississippi Hub, LLC (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 the Cameron LNG JV terminal 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 our Bay Gas and Mississippi Hub facilities, replacement sales contract rates have been and could continue to 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 either attract cash flow commitments sufficient to support further investment or extend its FERC construction permit beyond its current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage Pipeline, that is not contracted. Market conditions could result in the need to perform recovery testing of our recorded asset values. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent the recorded (carrying) value is in excess of the fair value, we would record a noncash impairment charge. The recorded value of our long-lived natural gas storage assets at December 31, 20152016 was $1.5 billion. A significant impairment charge related to our natural gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.

We provide information about these matters in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.

Our businesses, and the businesses that we invest in, are exposed to the risk that counterparties, business partners, customers, and suppliers that owe money or commodities as a result of market transactions or other long-term agreements or arrangements will not perform their obligations in accordance with such agreements or arrangements. Should they fail to perform, we may be required to enter into alternative arrangements or to honor the underlying commitment at then-current market prices. In such an event, we may incur additional losses to the extent of amounts already paid to such counterparties or suppliers. In addition, many such agreements are important for the conduct and growth of our businesses. The failure of any of the parties to perform in accordance with these agreements could materially adversely affect our businesses, results of operations, cash flows, financial condition and/or prospects. Finally, we often extend credit to counterparties and customers. While we perform significant credit analyses prior to extending credit, we are exposed to the risk that we may not be able to collect amounts owed to us.

Sempra Mexico’s and Sempra Natural Gas’LNG & Midstream’s obligations and those of their suppliers for LNG supplies are contractually subject to (1) suspension or termination for “force majeure” events beyond the control of the parties; and (2) substantial limitations of remedies for other failures to perform, including limitations on damages to amounts that could be substantially less than those necessary to provide full recovery of costs for breach of the agreements, which in either event could have a material adverse effect on our results of operations, cash flows, financial condition and/or prospects.

We are engaged in disputes regarding our title to the properties adjacent to and properties where our LNG terminal in Mexico is located, as we discuss in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. In the event that we are unable to defend and retain title to the properties on which our LNG terminal is located, we could lose our rights to occupy and use such properties and the related terminal, which could result in breaches of one or more permits or contracts that we have entered into with respect to such terminal. In addition, our ability to convert the LNG terminal into an export facility may be hindered by these disputes, and they could make project financing such a facility and finding suitable partners and customers very difficult. If we are unable to occupy and use such properties and the related terminal, it could have a material adverse effect on our businesses, financial condition, results of operations, cash flows and/or prospects.

Sempra Mexico and Sempra Natural GasLNG & Midstream also depend on natural gas pipelines to interconnect with their ultimate source or customers of the commodities they are transporting. Sempra Mexico and Sempra Natural GasLNG & Midstream also rely on specialized ships to transport LNG to their facilities and on natural gas pipelines to transport natural gas for customers of the facilities. Sempra Renewables, Sempra South American Utilities and Sempra Mexico rely on transmission lines to sell electricity to their customers. If transportation is disrupted, or if capacity is inadequate, we may be unable to sell and deliver our commodities, electricity and other services to some or all of our customers. As a result, we may be responsible for damages incurred by our customers, such as the additional cost of acquiring alternative electricity, natural gas supplies and LNG at then-current spot market rates, which could have a material adverse effect on our businesses, financial condition, cash flows, results of operations and/or prospects.